The Narragansett Electric Company

The Narragansett Electric CompanyFinancial StatementsFor the years ended March 31, 2021, 2020, and 2019

2 The Narragansett Electric Company 2021

THE NARRAGANSETT ELECTRIC COMPANY

TABLE OF CONTENTS Independent Auditors’ Report…………………………………………………………….………………………………………………………………..…3 Statements of Income

Years Ended March 31, 2021, 2020, and 2019……………………………………………………………………………………………………….…4 Statements of Cash Flows

Years Ended March 31, 2021, 2020, and 2019………………………………………………………………………………………………………….5 Balance Sheets

March 31, 2021 and 2020…………………………………………………………………………………………………………………………………………6 Statements of Capitalization

March 31, 2021 and 2020…………………………………………………………………………………………………………………………………………8 Statements of Changes in Shareholders’ Equity

Years Ended March 31, 2021, 2020, and 2019………………………………………………………………………………………………………….9 Notes to the Financial Statements:

1. Nature of Operations and Basis of Presentation……………………………………………………………………………….….….10

2. Summary of Significant Accounting Policies……………………………………………………………………………………………..11

3. Revenue…………………………………………………………………………………………………………………………………………………..18

4. Regulatory Assets and Liabilities………………………………………………………………………………………………………………20

5. Rate Matters………………………………………………………………………………………………………………………………………..….22

6. Property, Plant and Equipment………………………………………………………………………………………………………………..25

7. Derivative Instruments………………………………………………………………………………………………………………………….…26

8. Fair Value Measurements………………………………………………………………………………………………………………………..28

9. Employee Benefits…………………………………………………………………………………………………………………………………..29

10. Capitalization…………………………………………………………………………………………………………………………………………..38

11. Income Taxes…………………………………………………………………………………………………………………………………………..39

12. Environmental Matters……………………………………………………………………………………………………………………………41

13. Commitments and Contingencies………………………………………………………………………………………………..…….……42

14. Leases……………………………………………………………………………………………………………………………………………………..45

15. Related Party Transactions………………………………………………………………………………………………………………………46

INDEPENDENT AUDITORS' REPORT To the Board of Directors of The Narragansett Electric Company We have audited the accompanying financial statements of The Narragansett Electric Company (the "Company"), which comprise the balance sheets and statements of capitalization as of March 31, 2021 and 2020 and the related statements of income, cash flows, and changes in shareholders’ equity for each of the three years in the period ended March 31, 2021, and the related notes to the financial statements. Management’s Responsibility for the Financial Statements Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error. Auditors’ Responsibility Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion. Opinion In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of The Narragansett Electric Company as of March 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended March 31, 2021 in accordance with accounting principles generally accepted in the United States of America.

Emphasis of Matter As discussed in Note 1 and Note 5 to the financial statements, National Grid USA has agreed to sell 100 percent of the outstanding shares of common stock in the Company to PPL Rhode Island Holdings, LLC, a wholly owned indirect subsidiary of PPL Corporation. Our opinion is not modified with respect to this matter. September 27, 2021

mckcone

Stamp

The accompanying notes are an integral part of these financial statements.


THE NARRAGANSETT ELECTRIC COMPANYSTATEMENTS OF INCOME

(in thousands of dollars)

Years Ended March 31,

2021 2020 2019

Operating revenues $ 1,547,789 $ 1,556,566 $ 1,556,597

Operating expenses:

Purchased electricity 360,686 406,596 439,140

Purchased gas 162,502 158,387 173,829

Operations and maintenance 520,548 530,156 507,911

Depreciation 133,770 118,428 111,095

Other taxes 142,387 136,976 135,020

Total operating expenses 1,319,893 1,350,543 1,366,995

Operating income 227,896 206,023 189,602

Other income and (deductions):

Interest on long-term debt (63,654) (55,433) (51,573)

Other interest, including affiliate interest, net (1,930) (4,385) (4,060)

Other income, net 2,490 3,096 468

Total other deductions, net (63,094) (56,722) (55,165)

Income before income taxes 164,802 149,301 134,437

Income tax expense 29,826 26,895 24,001

Net income $ 134,976 $ 122,406 $ 110,436


The Narragansett Electric Company 2021 5

THE NARRAGANSETT ELECTRIC COMPANYSTATEMENTS OF CASH FLOWS



2021 2020 2019

Operating activities:Net income $ 134,976 $ 122,406 $ 110,436Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation 133,770 118,428 111,095Regulatory amortizations 426 427 (1,580)Deferred income tax 10,657 2,975 36,399Bad debt expense 33,140 38,360 23,856Amortization of debt discount and issuance costs 630 471 412Pension and postretirement benefit expenses, net (1,510) 1,562 (3,203)

Pension and postretirement benefit contributions (4,273) (4,542) (12,294)Environmental remediation payments (5,684) (1,932) (1,847)Changes in operating assets and liabilities:

Accounts receivable, net and unbilled revenues (98,413) 18,340 (35,717)Accounts receivable from/payable to affiliates, net 8,244 2,692 42,975Inventory 1,160 (526) (4,406)Regulatory assets and liabilities, net 18,514 (86,207) 66,431Derivative instruments (7,935) 15,089 (3,511)Prepaid and accrued taxes 6,240 12,551 14,707Accounts payable and other liabilities 55,639 (25,728) 30,294Other, net 14,558 3,272 (15,375)

Net cash provided by operating activities 300,139 217,638 358,672

Investing activities:Capital expenditures (346,413) (314,935) (305,013)Intercompany money pool (158,550) - -Cost of removal (24,910) (26,043) (26,652)Other (2,042) 175 (480)

Net cash used in investing activities (531,915) (340,803) (332,145)

Financing activities:Common stock dividends to Parent - - (85,250)Preferred stock dividends (110) (110) (110)Payments on long-term debt (11,375) (251,375) (15,839)Issuance of long-term debt 600,000 - 350,000Payment of debt issuance costs (2,839) - (1,893)Intercompany money pool (351,415) 294,868 (271,647)Equity infusion from Parent - 75,000 -

Net cash provided by (used in) financing activities 234,261 118,383 (24,739)

Net increase (decrease) in cash, cash equivalents, restricted cash and special deposits 2,485 (4,782) 1,788Cash, cash equivalents, restricted cash and special deposits, beginning of year 3,871 8,653 6,865

Cash, cash equivalents, restricted cash and special deposits, end of year $ 6,356 $ 3,871 $ 8,653

Supplemental disclosures:Interest paid $ (53,243) $ (55,612) $ (50,639)Income taxes (paid) refunded (220) (11,107) 15,746

Significant non-cash items:Capital-related accruals included in accounts payable 11,070 10,516 12,625Parent tax loss allocation 2,675 - -



THE NARRAGANSETT ELECTRIC COMPANYBALANCE SHEETS


March 31,

2021 2020

ASSETS

Current assets:Cash and cash equivalents $ 5,990 $ 3,420Restricted cash and special deposits 366 451Accounts receivable 314,047 233,444Allowance for doubtful accounts (63,390) (43,288)Accounts receivable from affiliates 17,386 19,674Intercompany moneypool asset 158,550 -Unbilled revenues 62,295 57,523Inventory 44,015 41,702Regulatory assets 71,917 98,179Derivative instruments 5,010 154Other 11,324 2,873

Total current assets 627,510 414,132

Property, plant and equipment, net 3,734,291 3,470,757

Non-current assets:Regulatory assets 451,963 513,869Goodwill 724,810 724,810Other 30,038 41,318

Total non-current assets 1,206,811 1,279,997

Total assets $ 5,568,612 $ 5,164,886



THE NARRAGANSETT ELECTRIC COMPANYBALANCE SHEETS


March 31,

2021 2020

LIABILITIES AND CAPITALIZATION

Current liabilities:

Accounts payable $ 147,033 $ 139,474

Accounts payable to affiliates 60,387 54,431

Intercompany moneypool liability - 351,415

Current portion of long-term debt 1,375 11,375

Taxes accrued 55,149 43,022

Customer deposits 11,519 11,733

Interest accrued 16,072 6,676

Regulatory liabilities 108,573 94,664

Derivative instruments 6,084 11,768

Renewable energy certificate obligations 31,372 19,878

Environmental remediation costs 22,588 13,938

Other 77,453 43,662

Total current liabilities 537,605 802,036

Other non-current liabilities:


Asset retirement obligations 9,399 9,738

Deferred income tax liabilities, net 392,222 367,318

Postretirement benefits 32,420 122,176


Other 41,999 35,208

Total other non-current liabilities 1,131,061 1,197,049

Commitments and contingencies (Note 13)

Capitalization:

Shareholders' equity 2,390,844 2,253,115

Long-term debt 1,509,102 912,686

Total capitalization 3,899,946 3,165,801

Total liabilities and capitalization $ 5,568,612 $ 5,164,886



THE NARRAGANSETT ELECTRIC COMPANYSTATEMENTS OF CAPITALIZATION


March 31,

2021 2020

Total shareholders' equity $ 2,390,844 $ 2,253,115

Long-term debt: Interest Rate Maturity Date

Unsecured notes:

Senior Notes 5.64% March 15, 2040 300,000 300,000

Senior Notes 4.17% December 10, 2042 250,000 250,000

Senior Notes 3.92% August 1, 2028 350,000 350,000

Senior Notes 3.40% April 9, 2030 600,000 -

1,500,000 900,000

First Mortgage Bonds ("FMB"):

FMB Series N 9.63% May 30, 2020 - 10,000

FMB Series O 8.46% September 30, 2022 12,500 12,500

FMB Series P 8.09% September 30, 2022 1,250 1,875

FMB Series R 7.50% December 15, 2025 3,750 4,500

17,500 28,875

Total debt 1,517,500 928,875

Unamortized debt discount (1,551) (1,646)

Unamortized debt issuance costs (5,472) (3,168)

Total debt less unamortized costs 1,510,477 924,061

Current portion of long-term debt 1,375 11,375

Total long-term debt 1,509,102 912,686

Total capitalization $ 3,899,946 $ 3,165,801


The Company had 1,132,487 shares of common stock authorized, issued and outstanding, with a par value of $50 per share and 49,089 shares of cumulative preferred stock authorized, issued and outstanding,with a par value of $50 per share at March 31, 2021 and 2020.

THE NARRAGANSETT ELECTRIC COMPANYSTATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY


Accumulated Other Comprehensive Income (Loss)

Cumulative Additional Unrealized Gain Pension and Total AccumulatedCommon Preferred Paid-in (Loss) on Available- Other Postretirement Hedging Other Comprehensive Retained

Stock Stock Capital For-Sale Securities Benefits Activity Income (Loss) Earnings Total

Balance as of March 31, 2018 $ 56,624 $ 2,454 $ 1,358,057 $ 931 $ 1,301 $ (2,973) $ (741) $ 614,509 $ 2,030,903Net income - - - - - - - 110,436 110,436Other comprehensive income (loss):

Unrealized loss on securities, net of $3 tax benefit - - - (12) - - (12) - (12)

Change in pension and other postretirementobligations, net of $182 tax benefit - - - - (683) - (683) - (683)

Unrealized gains on hedges, net of $67 tax expense - - - - - 254 254 - 254

Total comprehensive income 109,995

Common stock dividends to Parent - - - - - - - (85,250) (85,250)Preferred stock dividends - - - - - - - (110) (110)Impact of adoption of recognition and measurement of

financial assets and liabilities standard - - - (896) - - (896) 896 -

Balance as of March 31, 2019 $ 56,624 $ 2,454 $ 1,358,057 $ 23 $ 618 $ (2,719) $ (2,078) $ 640,481 $ 2,055,538Net income - - - - - 122,406 122,406Other comprehensive income (loss):

Unrealized gain on securities, net of $42 tax expense - - - 158 - - 158 - 158Change in pension and other postretirement

obligations, net of $34 tax benefit - - - - (127) - (127) - (127)Unrealized gains on hedges, net of $66 tax expense - - - - - 250 250 - 250


Equity infusion from Parent - - 75,000 - - - - - 75,000Preferred stock dividends - - - - - - - (110) (110)Impact of adoption of reclassification of certain tax from

accumulated other comprehensive income standard - - - 8 (1,409) (664) (2,065) 2,065 -

Balance as of March 31, 2020 $ 56,624 $ 2,454 $ 1,433,057 $ 189 $ (918) $ (3,133) $ (3,862) $ 764,842 $ 2,253,115Net income - - - - - 134,976 134,976Other comprehensive income:

Unrealized gain on securities, net of $4 tax expense - - - 15 - - 15 - 15Change in pension and other postretirement

obligations, net of $4 tax expense - - - - 14 - 14 - 14Unrealized gains on hedges, net of $42 tax expense - - - - - 159 159 - 159


Parent tax loss allocation - - 2,675 - - - - - 2,675Preferred stock dividends - - - - - - - (110) (110)

Balance as of March 31, 2021 $ 56,624 $ 2,454 $ 1,435,732 $ 204 $ (904) $ (2,974) $ (3,674) $ 899,708 $ 2,390,844


THE NARRAGANSETT ELECTRIC COMPANYNOTES TO THE FINANCIAL STATEMENTS

1. NATURE OF OPERATIONS AND BASIS OF PRESENTATION

The Narragansett Electric Company (“the Company”) is a retail distribution company providing electric service toapproximately 509,000 customers and gas service to approximately 274,000 customers in 38 cities and towns in Rhode Island.The Company’s service area covers substantially all of Rhode Island.

The Company is a wholly-owned subsidiary of National Grid USA (“NGUSA” or the “Parent”), a public utility holding companywith regulated subsidiaries engaged in the generation of electricity and the transmission, distribution, and sale of both naturalgas and electricity. NGUSA is a direct wholly-owned subsidiary of National Grid North America Inc. (“NGNA”) and an indirectwholly-owned subsidiary of National Grid plc, a public limited company incorporated under the laws of England and Wales.

On March 18, 2021 it was announced that the Company will be sold to PPL Corporation, as part of a transaction with NationalGrid PLC in which National Grid PLC will acquire PPL Corporation's Western Power Distribution. The expected sale proceedsis $3.8 billion, and the sale is expected to be completed in March 2022 once all regulatory approvals are obtained.

The accompanying financial statements are prepared in accordance with accounting principles generally accepted in theUnited States of America (“U.S. GAAP”), including the accounting principles for rate-regulated entities. The financialstatements reflect the ratemaking practices of the applicable regulatory authorities.

The novel coronavirus (“COVID-19”) pandemic has disrupted the U.S. and global economies and continues to have asignificant impact on global health. In March 2020, COVID-19 was declared a pandemic by the World Health Organization(“WHO”) and the Centers for Disease Control and Prevention. In March 2020, the Company ceased certain customer cashcollection activities in response to regulatory instructions and to changes in State, Federal and City level regulations andguidance, and actions to minimize risk to employees. The Company has also ceased customer termination activities asrequested by relevant local authorities.

The Company has seen adverse impacts from COVID-19 on earnings and cash flow. Earnings are impacted by increasedincremental costs, increased bad debt expense, lower capitalization rates of workforce costs, and reduced late paymentrevenues, slightly offset by reduced costs and other mitigation efforts by the Company. Cash flow is negatively impacted bythe higher level of operating costs, and lower cash collections from customers because of the moratorium on disconnectionsand the economic slowdown resulting from the COVID-19 pandemic, including: (1) increase in aged receivables and bad debtexpenses, (2) lost revenue from unassessed late payment charges, and (3) changes to the Company for other fees that theCompany has waived pursuant to the PUC’s orders. As of March 31, 2021, the Company recorded additional reserves foruncollectible accounts related to the COVID-19 pandemic’s impact on the Company’s electric and gas businesses.

Despite the negative impacts on cash flow, the Company has maintained access to National Grid’s money pool, which hasinsulated the Company from immediate impacts on liquidity. Similarly, there has also been no impact on access to capital atpresent.

The Company has evaluated subsequent events and transactions through September 27, 2021, the date of issuance of thesefinancial statements, and concluded that there were no events or transactions that require adjustment to, or disclosure in,the financial statements as of and for the year ended March 31, 2021. The Company continues to evaluate the ongoing impactof COVID-19 on both customers and financial performance and is complying with the request from the Rhode Island PublicUtilities Commission (“RIPUC”) to share relevant information.


2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

In preparing financial statements that conform to U.S. GAAP, the Company must make estimates and assumptions that affect thereported amounts of assets, liabilities, revenues, and expenses, and the disclosure of contingent assets and liabilities included inthe financial statements. Such estimates and assumptions include the impact of the ongoing COVID-19 pandemic and are reflectedin the accompanying financial statements. Actual results could differ from those estimates.

Regulatory Accounting

The Federal Energy Regulatory Commission (“FERC”), the RIPUC, and the Rhode Island Division of Public Utilities and Carriers(“Division”) regulate the rates the Company charges its customers. In certain cases, the rate actions of the FERC, RIPUC andDivision can result in accounting that differs from non-regulated companies. In these cases, the Company defers costs (asregulatory assets) or recognizes obligations (as regulatory liabilities) if it is probable that such amounts will be recoveredfrom, or refunded to, customers through future rates. In accordance with Accounting Standards Codification (“ASC”) 980,“Regulated Operations,” regulatory assets and liabilities are reflected on the balance sheet consistent with the treatment ofthe related costs in the ratemaking process.

Revenue Recognition

Revenues are recognized for energy service billed on a monthly cycle basis, together with unbilled revenues for the estimatedamount of services rendered from the time meters were last read to the end of the accounting period (See Note 3, “Revenue”for additional details).

Other Taxes

The Company collects taxes and fees from customers such as sales taxes, other taxes, surcharges, and fees that are levied bystate or local governments on the sale or distribution of gas and electricity. The Company accounts for taxes that are imposedon customers (such as sales taxes) on a net basis (excluded from revenues), while taxes imposed on the Company, such asexcise taxes, are recognized on a gross basis. Excise taxes collected and expected to be paid for the years ended March 31,2021, 2020, and 2019 were $54.7 million, $54.8 million, and $54.9 million, respectively.

The Company’s policy is to accrue for property taxes on a calendar year basis.

Income Taxes

Federal income taxes have been computed utilizing the asset and liability approach that requires the recognition of deferredtax assets and liabilities for the tax consequences of temporary differences by applying enacted statutory tax rates applicableto future years to differences between the financial statement carrying amounts and the tax basis of existing assets andliabilities. Deferred income taxes also reflect the tax effect of net operating losses, capital losses, and general business creditcarryforwards. The Company assesses the available positive and negative evidence to estimate whether enough futuretaxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. Whenthe evaluation of the evidence indicates that the Company will not be able to realize the benefits of existing deferred taxassets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount.

The effects of tax positions are recognized in the financial statements when it is more likely than not that the position taken,or expected to be taken, in a tax return will be sustained upon examination by taxing authorities based on the technical meritsof the position. The financial effect of changes in tax laws or rates is accounted for in the period of enactment. Deferredinvestment tax credits are amortized over the useful life of the underlying property.

NGNA files consolidated federal tax returns including all of the activities of its subsidiaries. Each subsidiary determines its taxprovision based on the separate return method, modified by a benefits-for-loss allocation pursuant to a tax sharing


agreement between NGNA and its subsidiaries. The benefit of consolidated tax losses and credits are allocated to the NGNAsubsidiaries giving rise to such benefits in determining each subsidiary’s tax expense in the year that the loss or credit arises.In a year that a consolidated loss or credit carryforward is utilized, the tax benefit utilized in consolidation is paidproportionately to the subsidiaries that gave rise to the benefit regardless of whether that subsidiary would have utilized thebenefit. The tax sharing agreement also requires NGNA to allocate its parent tax losses, excluding deductions from acquisitionindebtedness, to each subsidiary in the consolidated federal tax return with taxable income. The allocation of NGNA’s parenttax losses to its subsidiaries is accounted for as a capital contribution and is performed in conjunction with the annualintercompany cash settlement process following the filing of the federal tax return.

Cash and Cash Equivalents

Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less. Cash andcash equivalents are carried at cost which approximates fair value.

Restricted Cash and Special Deposits

Restricted cash and special deposits consists of collateral paid to the Company’s counterparties for outstanding derivativeinstruments. The Company had restricted cash and special deposits of $0.4 million and $0.5 million as of March 31, 2021 and2020, respectively.

Accounts Receivable and Allowance for Doubtful Accounts

The Company recognizes an allowance for doubtful accounts to record accounts receivable at estimated net realizable value.The allowance is determined based on a variety of factors including, for each type of receivable, applying an estimated reservepercentage to each aging category, taking into account historical collection and write-off experience, and management'sassessment of collectability from individual customers, as appropriate. The collectability of receivables is continuouslyassessed and, if circumstances change, the allowance is adjusted accordingly. Receivable balances are written off against theallowance for doubtful accounts when the accounts are disconnected and/or terminated and the balances are deemed to beuncollectible. The Company recorded bad debt expense of $33.1 million, $38.4 million and $23.9 million for the years endedMarch 31, 2021, 2020 and 2019, respectively, within operation and maintenance expenses in the accompanying statementsof income. For the years ended March 31, 2021 and 2020, bad debt expense reflects the estimated impact of COVID-19.

Inventory

Inventory is composed of materials and supplies, purchased Renewable Energy Certificates (“RECs”), and gas in storage.Materials and supplies are stated at weighted average cost, which represents net realizable value, and are expensed orcapitalized as used. Purchased RECs are stated at cost. There were no significant write-offs of obsolete inventory for the yearsended March 31, 2021, 2020, or 2019.

Gas in storage is stated at weighted average cost and the related cost is recognized when delivered to customers. Existingrate orders allow the Company to pass directly through to customers the cost of gas purchased, along with any applicableauthorized delivery surcharge adjustments. Gas costs passed through to customers are subject to regulatory approvals andare reported periodically to the RIPUC.

The Company had materials and supplies of $12.8 million and $12.0 million, purchased RECs of $22.0 million and $18.5 million,and gas in storage of $9.3 million and $11.2 million as of March 31, 2021 and 2020, respectively.

Renewable Energy Standard Obligation

RECs are stated at cost and are used to measure compliance with State renewable energy standards. RECs support newrenewable generation standards and are held primarily to be utilized in fulfillment of the Company’s compliance obligations.As of March 31, 2021, and 2020, the Company recorded a renewable energy standard obligation of $31.4 million and $19.9million, respectively, within renewable energy certificate obligations.


Derivative Instruments

The Company uses derivative instruments to manage commodity price risk. All derivative instruments, except those thatqualify for the normal purchase normal sale exception, are recorded on the balance sheet at fair value. All commodity costs,including the impact of derivative instruments, are passed on to customers through the Company’s commodity rateadjustment mechanisms. Regulatory assets or regulatory liabilities are recorded to defer the recognition of unrealized lossesor gains on derivative instruments, respectively. The gains or losses on the settlement of these contracts are recognized aspurchased gas on the statements of income and then refunded to, or collected from, customers consistent with regulatoryrequirements.

The Company has certain non-trading instruments for the physical purchase of electricity that qualify for the normal purchasenormal sale exception and are accounted for upon settlement. If the Company were to determine that a contract no longerqualifies for the normal purchase normal sale exception, then the Company would recognize the fair value of the contractand account for the gains and losses using the regulatory accounting described above.

The Company’s accounting policy is to not offset fair value amounts recognized for derivative instruments and related cashcollateral receivable or payable with the same counterparty under a master netting agreement, but rather to record andpresent the fair value of the derivative instrument on a gross basis, with related cash collateral recorded within restrictedcash and special deposits on the balance sheet.

Fair Value Measurements

The Company measures derivative instruments, securities and pension and postretirement benefit other than pension planassets at fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderlytransaction between market participants at the measurement date. The following is the fair value hierarchy that prioritizesthe inputs to valuation techniques used to measure fair value:

- Level 1: quoted prices (unadjusted) in active markets for identical assets or liabilities that a company has the abilityto access as of the reporting date;

- Level 2: inputs other than quoted prices included within Level 1 that are directly observable for the asset or liabilityor indirectly observable through corroboration with observable market data;

- Level 3: unobservable inputs, such as internally-developed forward curves and pricing models for the asset or liabilitydue to little or no market activity for the asset or liability with low correlation to observable market inputs; and

- Not categorized: Investments in certain funds, that meet certain conditions of ASC 820, are not required to becategorized within the fair value hierarchy. These investments are typically in commingled funds or limitedpartnerships that are not publicly traded and have ongoing subscription and redemption activity. As a practicalexpedient, the fair value of these investments is the Net Asset Value (“NAV”) per fund share.

The asset or liability’s fair value measurement level within the fair value hierarchy is based on the lowest level of any inputthat is significant to the fair value measurement. The Company uses valuation techniques that maximize the use of observableinputs and minimize the use of unobservable inputs.

Property, Plant and Equipment

Property, plant and equipment is stated at original cost. The capitalized cost of additions to property, plant and equipmentincludes costs such as direct material, labor and benefits, and an allowance for funds used during construction (“AFUDC”).The cost of repairs and maintenance is charged to expense and the cost of renewals and betterments that extend the usefullife of property, plant and equipment is capitalized.


Depreciation is computed over the estimated useful life of the asset using the composite straight-line method. Depreciationstudies are conducted periodically to update the composite rates and are approved by the FERC and RIPUC. The averagecomposite rates for the years ended March 31, 2021, 2020 and 2019 are as follows:

Composite Rates

March 31,

2021 2020 2019

Electric 3.0% 2.9% 3.0%

Gas 3.1% 3.1% 3.4%

Depreciation expense includes a component for the estimated cost of removal, which is recovered through rates charged tocustomers. Any difference in cumulative costs recovered and costs incurred is recognized as a regulatory liability. Whenproperty, plant and equipment is retired, the original cost, less salvage, is charged to accumulated depreciation, and therelated cost of removal is removed from the associated regulatory liability. The Company recognized a regulatory liability forthe amount that was in excess of costs incurred of $238.9 million and $226.3 million as of March 31, 2021 and 2020,respectively.

Allowance for Funds Used During Construction

The Company records AFUDC, which represents the debt and equity costs of financing the construction of new property,plant and equipment. The equity component of AFUDC is reported in the accompanying statements of income as non-cashincome in other income, net. The debt component of AFUDC is reported as a non-cash offset to other interest, includingaffiliate interest. After construction is completed, the Company is permitted to recover these costs through their inclusion inrates. The Company recorded AFUDC related to equity of $5.8 million, $1.7 million, and $4.3 million, and AFUDC related todebt of $2.3 million, $2.0 million, and $2.5 million, for the years ended March 31, 2021, 2020, and 2019, respectively. Theaverage AFUDC rates for the years ended March 31, 2021, 2020, and 2019 were 7.5%, 4.4%, and 5.7% respectively.

Impairment of Long-Lived Assets

The Company tests the impairment of long-lived assets when events or changes in circumstances indicate that the carryingamount of the asset (or asset group) may not be recoverable. If identified, the recoverability of an asset is determined bycomparing its carrying value to the estimated undiscounted cash flows that the asset is expected to generate. If thecomparison indicates that the carrying value is not recoverable, an impairment loss is recognized for the excess of the carryingvalue over the estimated fair value. For the years ended March 31, 2021, 2020, and 2019, there were no impairment lossesrecognized for long-lived assets.

Goodwill

The Company tests goodwill for impairment annually on January 1, or more frequently if events occur or circumstances exist thatindicate it is more likely than not that the fair value of the Company is below its carrying amount. The Company has early adoptedAccounting Standards Update (“ASU”) No. 2017-04, “Intangibles—Goodwill and Other (Topic 350): Simplifying the Test forGoodwill Impairment,” which eliminates step two from the two-step goodwill impairment test previously required under theformer standard. The goodwill impairment test requires a recoverability test performed based on the comparison of theCompany’s estimated fair value with its carrying value, including goodwill. If the estimated fair value exceeds the carrying value,then goodwill is not considered impaired. If the carrying value exceeds the estimated fair value, the Company is required torecognize an impairment charge for such excess, limited to the carrying amount of goodwill.

The Company elected to perform a qualitative assessment to determine whether it is more likely than not that the carrying valueof the Company exceeds its estimated fair value and an impairment exists. The qualitative assessment is commonly referred to asthe “Step 0” test and requires the Company to evaluate relevant events and circumstances including, but not limited to,macroeconomic conditions, industry and market considerations, cost factors, and other relevant entity-specific events that mayindicate the existence of a decline in fair value that is other than temporary. The qualitative assessment indicated that it was more


likely than not that the fair value of the Company exceeds its carrying value and, as such, no impairment loss exists for the yearended March 31, 2021. The Company did not record any goodwill impairment during the years ended March 31, 2021, 2020 and2019.

Employee Benefits

The Company participates with other NGUSA subsidiaries in defined benefit pension plans and postretirement benefit otherthan pension (“PBOP”) plans for its employees, administered by NGUSA. The Company recognizes its portion of the pensionand PBOP plans’ funded status on the balance sheet as a net liability or asset. The cost of providing these plans is recoveredthrough rates; therefore, the net funded status is offset by a regulatory asset or liability. The pension and PBOP plans’ assetsare commingled and allocated to measure and record pension and PBOP funded status at each year-end date. Pension andPBOP plan assets are measured at fair value, using the year-end market value of those assets.

Supplemental Executive Retirement Plans

The Company has corporate assets included in other non-current assets on the balance sheet representing funds designatedfor Supplemental Executive Retirement Plans, nonqualified retirement and deferred compensation benefits. These funds areinvested in corporate owned life insurance policies and securities primarily consisting of equity investments and investmentsin municipal and corporate bonds. The corporate owned life insurance investments are measured at cash surrender value orat fair value, with increases and decreases in the value of these assets recorded in the accompanying statements of income.

Leases

The Company adopted Topic 842 during the year ended March 31, 2020. The Company elected the practical expedient“package” in which any expired contracts were not reassessed to determine whether they met the definition of a lease;classification of leases that commenced prior to the adoption of this standard was not reassessed; and any initial direct costsfor existing leases were not reassessed. Additionally, the Company elected the practical expedient to not reassess existingeasements that were not previously accounted for as leases under Topic 840.

The Company has elected to not evaluate whether sales tax and other similar taxes are lessor and lessee costs. Instead, suchcosts are deemed lessee costs. The Company does not combine lease and non-lease components for contracts in which theCompany is the lessee or the lessor.

Certain building leases provide the Company with an option to extend the lease term. The Company has included the periodscovered by an extension options in its determination of the lease term when management believes it is reasonably certainthe Company will exercise its option.

Lease liabilities are recognized based on the present value of the lease payments over the lease term at the commencementdate. For any leases that do not provide an implicit rate, the Company uses an estimate of its collateralized incrementalborrowing rate based on the information available at the commencement date to determine the present value of futurepayments. In measuring lease liabilities, the Company excludes variable lease payments, other than those that depend on anindex or a rate, or are in substance fixed payments, and includes lease payments made at or before the commencement date.Variable lease payments were not material for the years ended March 31, 2021 and 2020. The Company does not reflectshort-term leases on the balance sheets. Expense related to short-term leases was not material for the years ended March31, 2021 and 2020.

Right-of-use assets consist of the lease liability, together with any payments made to the lessor prior to commencement ofthe lease (less any lease incentives) and any initial direct costs. Right-of-use assets are amortized over the lease term.

The Company recognizes lease expense based on a pattern that conforms to the regulatory ratemaking treatment.


New and Recent Accounting Guidance

Accounting Guidance Recently Adopted

Fair Value

In August 2018, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2018-13 “Fair Value Measurement (Topic820): Disclosure Framework–Changes to the Disclosure Requirements for Fair Value Measurement” which modifies certaindisclosure requirements on fair value measurements in Topic 820, Fair Value Measurement, including certain disclosurerequirements relating to Level 3 fair value measurements, and eliminates disclosure requirements for transfers betweenLevel 1 and Level 2 fair value measurements. The standard also added certain other disclosure requirements for Level 3 fairvalue measurements. The Company adopted this new guidance on April 1, 2020 requiring certain revisions to disclosuresrelated to recurring fair value measurements in Note 8, “Fair Value Measurements. Upon adoption, the amendments in thestandard were applied retrospectively to all periods presented, except the amendments on changes in unrealized gains andlosses, the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements,and the narrative description of measurement uncertainty, which were applied prospectively for only the most recent annualperiod presented. The amendments did not materially affect the Company’s disclosures and did not affect the Company’sfinancial position, results of operations, or cash flows.

Pension and Postretirement Benefits

In August 2018, the FASB issued ASU No. 2018-14 “Compensation—Retirement Benefits—Defined Benefit Plans—General(Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans,” whichmodifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans andeliminates certain disclosure requirements. The Company adopted this new guidance on April 1, 2020 using a retrospectivebasis to all periods presented, resulting in certain revisions to disclosures related to the Company’s defined benefit plans inNote 9, “Employee Benefits”. The amendments did not materially affect the Company’s disclosures related to its definedbenefit postretirement benefit plans and did not affect the Company’s financial position, results of operations, or cash flows.

Internal-Use Software

In August 2018, the FASB issued ASU No. 2018-15 “Intangibles–Goodwill and Other–Internal-Use Software (Subtopic 350-40):Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that Is a Service Contract” tohelp entities evaluate the accounting for fees paid by a customer under a cloud computing arrangement that is a servicecontract. The amendment aligns the requirements for capitalizing implementation costs incurred in a hosting arrangementthat is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. Under this standard, the Company applies Subtopic 350-40 to determine which implementation costs relatedto a hosting arrangement should be capitalized or expensed. The Company expenses the capitalized implementation costs ofa hosting arrangement that is a service contract over the term of the arrangement. The Company adopted this new guidanceprospectively on April 1, 2020. The amendments did not materially impact the Company’s financial position, results ofoperations, or cash flows.

Accounting Guidance Not Yet Adopted

Income Taxes

In December 2019, the FASB issued ASU No. 2019-12 “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes”which simplifies various aspects of the accounting for income taxes by eliminating certain exceptions to current requirements.The standard also enhances and simplifies other requirements, including tax basis step-up in goodwill obtained in atransaction that is not a business combination, ownership changes in investments, and interim-period accounting for enactedchanges in tax law. For public business entities, the standard is effective for fiscal years, and interim periods within thosefiscal years, beginning after December 15, 2020. For all other entities, the standard is effective for fiscal years beginning afterDecember 15, 2021, and interim periods within fiscal years beginning after December 15, 2022. Early adoption is permitted.


The Company plans to early adopt this standard on April 1, 2021, and interim periods within. The Company does not expectthe adoption to have a material impact on its financial statements.

Investments – Equity Securities

In January 2020, the FASB issued ASU No. 2020-01 “Investments—Equity Securities (Topic 321), Investments—Equity Methodand Joint Ventures (Topic 323), and Derivatives and Hedging (Topic 815): Clarifying the Interactions between Topic 321, Topic323, and Topic 815 (a consensus of the FASB Emerging Issues Task Force)” which clarifies that an entity should considertransaction prices for purposes of measuring the fair value of certain equity securities immediately before applying or upondiscontinuing the equity method. This accounting standard also clarifies that when accounting for contracts entered into topurchase equity securities, an entity should not consider whether, upon the settlement of the forward contract or exerciseof the purchased option, the underlying securities would be accounted for under the equity method or the fair value option.For public business entities, the standard is effective for fiscal years, and interim periods within those fiscal years, beginningafter December 15, 2020. For all other entities, the standard is effective for fiscal years, and interim periods within thosefiscal years, beginning after December 15, 2021. Early adoption is permitted. The Company plans to early adopt this standardon April 1, 2021, and interim periods within. The Company does not expect the adoption to have a material impact on itsfinancial statements.

Callable Debt Securities

In October 2020, the FASB issued ASU No. 2020-08 “Codification Improvements to Subtopic 310-20, Receivables –Nonrefundable Fees and Other Costs” to clarify that an entity must reevaluate whether a callable debt security with multiplecall dates is within the scope of paragraph ASC 310-20-35-33 for each reporting period such that the premium should beamortized over the period ending at the earliest call date. For public business entities, the standard is effective for fiscal years,and interim periods within those fiscal years, beginning after December 15, 2020. Early application is not permitted for publicbusiness entities. The Company will adopt this standard prospectively on April 1, 2021, and interim periods within. TheCompany does not expect the adoption to have a material impact on its financial statements.

Financial Instruments – Credit Losses

In June 2016, the FASB issued ASU No. 2016-13 “Financial Instruments–Credit Losses (Topic 326): Measurement of CreditLosses on Financial Statements” which requires a financial asset (or a group of financial assets) measured at amortized costbasis to be presented at the net amount expected to be collected. The accounting standard provides a new model forrecognizing credit losses on financial instruments based on an estimate of current expected credit losses that replaces existingincurred loss impairment methodology requiring delayed recognition of credit losses. A broader range of reasonable andsupportable information must be considered in developing estimates of credit losses. The allowance for credit losses is avaluation account that is deducted from the amortized cost basis of the financial asset(s) to present the net carrying value atthe amount expected to be collected on the financial asset. Credit losses relating to available-for-sale debt securities shouldbe recorded through an allowance for credit losses. In May 2019, the FASB issued ASU 2019-05, “Financial Instruments—Credit Losses (Topic 326): Targeted Transition Relief”, permitting entities to irrevocably elect the fair value option for financialinstruments that were previously recorded at amortized cost basis within the scope of Topic 326, except for held-to-maturitydebt securities. For the Company, the requirements in these updates, as amended in November 2019 by ASU 2019-10“Financial Instruments—Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842): EffectiveDates”, will be effective for fiscal years beginning after December 15, 2022 (beginning April 1, 2023 for the Company),including interim periods within those fiscal years. The Company is currently assessing the application of this standard todetermine if it will have a material impact on the presentation, results of operations, cash flows, and financial position of theCompany.

Reclassifications

Certain reclassifications have been made to the financial statements to conform the prior period’s balances to the currentperiod’s presentation. These reclassifications had no effect on reported income, statement of cash flows, total assets, orshareholders’ equity as previously reported.


3. REVENUE

The following table presents, for the years ended March 31, 2021, 2020 and 2019, revenue from contracts with customers,as well as additional revenue from sources other than contracts with customers, disaggregated by major source:

Years ended March 31

2021 2020 2019


Revenue from contracts with customers:

Electric services $ 1,135,865 $ 1,055,161 1,130,618

Gas distribution 457,123 416,015 482,793

Total revenue from contracts with customers 1,592,988 1,471,176 1,613,411

Revenue from regulatory mechanisms (45,199) 85,390 (56,814)

Total operating revenues $ $1,547,789 $ 1,556,566 1,556,597

Electric Services and Gas Distribution: Revenue from contracts with customers, includes electric services and gas distribution.Electric services are comprised of electric distribution and transmission services.

The Company owns and maintains an electric and natural gas distribution network in Rhode Island. Distribution revenues areprimarily from the sale of electricity, gas, and related services to retail customers. Distribution sales are regulated by theRIPUC, which is responsible for determining the prices and other terms of services as part of the rate making process. Thearrangement where a utility provides a service to a customer in exchange for a price approved by a regulator is referred toas a tariff sales contract. Gas and electric distribution revenues are derived from the regulated sale and distribution ofelectricity and natural gas to residential, commercial, and industrial customers within the Company’s service territory underthe tariff rates. The tariff rates approved by the regulator are designed to recover the costs incurred by the Company forproducts and services provided and along with a return on investment.

The performance obligation related to distribution sales is to provide electricity and natural gas to customers on demand.The electricity and natural gas supplied under the respective tariff each represents a single performance obligation as it is aseries of distinct goods or services that are substantially the same. The performance obligation is satisfied over time becausethe customer simultaneously receives and consumes the electricity or natural gas as the Company provides these services.The Company records revenues related to the distribution sales based upon the approved tariff rate and the volume deliveredto the customers, which corresponds with the amount the Company has the right to invoice.

The distribution revenue also includes estimated unbilled amounts, which represent the estimated amounts due from retailcustomers for electricity and natural gas provided to customers by the Company, but not yet billed. Unbilled revenues aredetermined based on estimated unbilled sales volumes for the respective customer classes and then applying the applicabletariff rate to those volumes. Actual amounts billed to customers when the meter readings occur, may be different from theestimated amounts.

Certain customers have the option to obtain electricity or natural gas from other suppliers. In those circumstances, revenueis only recognized for providing delivery of the commodity to the customer.

Additionally, the Company owns an electric transmission system in Rhode Island. Transmission systems generally includeoverhead lines, underground cables, and substations, connecting generation and interconnectors to the distribution system.The Company’s transmission services are regulated by both the Independent System Operator (“ISO”) – New England and bythe FERC. Additionally, the Company makes available its transmission facilities to New England Power (“NEP,” an NGUSAaffiliate), for operation and control pursuant to an integrated facilities agreement, Service Agreement No. 23 (IntegratedFacilities Agreement or “IFA”). See Note 15 “Related Party Transactions” for additional details. These revenues arise undertariff/rate agreements and are collected primarily from the Company’s Rhode Island distribution customers.


Revenue from Regulatory Mechanisms: The Company records revenues in accordance with accounting principles for rate-regulated operations for arrangements between the Company and the regulator, which are not accounted for as contractswith customers. These include various deferral mechanisms such as capital trackers, energy efficiency programs, and otherprograms that also qualify as Alternative Revenue Programs (“ARPs”). ARPs enable the Company to adjust rates in the future,in response to past activities or completed events. The Company’s electric and gas distribution rates both have a revenuedecoupling mechanism (“RDM”), which allows for annual adjustments to the Company’s delivery rates as a result of thereconciliation between allowed revenue and billed revenue. The Company also has other ARPs related to the achievement ofcertain objectives, demand side management initiatives, and certain other rate making mechanisms. The Company recognizesARPs with a corresponding offset to a regulatory asset or liability account when the regulatory specified events or conditionshave been met, when the amounts are determinable, and are probable of recovery (or payment) through future rateadjustments.


4. REGULATORY ASSETS AND LIABILITIES

The Company records regulatory assets and liabilities that result from the ratemaking process. The following table presentsthe regulatory assets and regulatory liabilities recorded on the balance sheets:

March 31,

2021 2020

(in thousands of dollars)Regulatory assets

Current:Derivative instruments $ 6,221 $ 14,157Rate adjustment mechanisms 52,648 72,805Renewable energy certificates 9,416 1,395Revenue decoupling mechanism - 8,474Other 3,632 1,348

Total 71,917 98,179

Non-current:Environmental response costs 110,009 119,020Net metering 37,669 26,252Postretirement benefits 122,878 214,448Storm costs 131,382 120,207Other 50,025 33,942

Total $ 451,963 $ 513,869

Regulatory liabilitiesCurrent:

Energy efficiency $ 21,154 $ 20,654Gas cost adjustment - 2,894Rate adjustment mechanisms 66,867 44,561Revenue decoupling mechanism 14,448 11,237Transmission service 4,491 15,318Other 1,613 -

Total 108,573 94,664

Non-current:Cost of removal 238,863 226,279Energy efficiency 36,330 15,715Environmental response costs 16,155 18,839Regulatory tax liability, net 258,705 272,901Other 15,721 23,034

Total $ 565,774 $ 556,768

Other than $159.1 million of the regulatory assets summarized above ($120.4 million of Postretirement benefits, $37.7 millionof Net metering deferral costs and $1 million other costs), all regulatory assets earn a rate of return.

Cost of removal: Represents cumulative amounts collected, but not yet spent, to dispose of property, plant and equipment.This liability is discharged as removal costs are incurred.

Derivative instruments: The Company evaluates open derivative instruments for regulatory deferral by determining if theyare probable of recovery from, or refund to, customers through future rates. Derivative instruments that qualify for recoveryare recorded at fair value, with changes in fair value recorded as regulatory assets or regulatory liabilities in the period inwhich the change occurs.


Energy efficiency: Represents the difference between revenue billed to customers through the Company’s energy efficiencycharge and the costs of the Company’s energy efficiency programs as approved by the RIPUC.

Environmental response costs: The regulatory asset represents deferred costs associated with the Company’s share of theestimated costs to investigate and perform certain remediation activities at sites with which it may be associated. TheCompany’s rate plans provide for specific rate allowances for these costs, with variances deferred for future recovery from,or return to, customers. The Company believes future costs, beyond the expiration of current rate plans, will continue to berecovered through rates. The regulatory liability represents the excess of amounts received in rates over the Company’sactual site investigation and remediation costs.

Gas costs adjustment: The Company is subject to rate adjustment mechanisms for commodity costs, whereby an asset orliability is recognized resulting from differences between billed revenues and the underlying cost being recovered, asapproved by the RIPUC. These amounts will be refunded to, or recovered from, customers over the next year.

Net metering: Net metering deferral reflects the recovery mechanism for costs associated with customer installed on-sitegeneration facilities, including the costs of renewable generation credits. This surcharge provides the Company with amechanism to recover such amounts.

Postretirement benefits: The regulatory asset represents the Company’s unamortized non-cash accrual of net actuarial gainsand losses, offset by the excess amounts received in rates over actual costs of the Company’s pension and PBOP plans, thatare to be recovered from or passed back to customers in future periods.

Rate adjustment mechanisms: In addition to commodity costs, the Company is subject to a number of additional rateadjustment mechanisms whereby an asset or liability is recognized resulting from differences between actual revenues andthe underlying cost being recovered or differences between actual revenues and targeted amounts as approved by the RIPUC.

Regulatory tax liability, net: Represents over-recovered federal deferred taxes of the Company primarily as a result ofregulatory flow through accounting treatment and excess federal deferred taxes as a result of the Tax Cuts and Jobs Act of2017 (“Tax Act”).

Renewable energy certificates: Represents deferred costs associated with the Company’s compliance obligation with theRhode Island Renewable Portfolio Standard (“RPS”). The RPS is legislation established to foster the development of newrenewable energy sources. The regulatory asset will be recovered over the next year.

Revenue decoupling mechanism: As approved by the RIPUC, the Company has electric and gas RDMs which allow for anannual adjustment to the Company's delivery rates as a result of the reconciliation between allowed and billed revenues. Anydifference is recorded as a regulatory asset or regulatory liability.

Storm costs: The Company is allowed to recover storm costs from all retail delivery service customers. This balance reflectscosts yet to be recovered.

Transmission service: The Company arranges transmission service on behalf of its customers and bills the costs of thoseservices to customers, pursuant to the Company’s Transmission Service Cost Adjustment Provision. Any over or underrecoveries of these costs are passed on to customers receiving transmission service over the subsequent year.

The Company records carrying charges on regulatory balances for which cash expenditures have been made and are subjectto recovery, or for which cash has been collected and is subject to refund, as approved in accordance with the RIPUC. Carryingcharges are not recorded on items for which expenditures have not yet been made.


5. RATE MATTERS

General Rate Case

On August 24, 2018 and pursuant to Report and Order No. 23823 issued May 5, 2020, the RIPUC approved the terms of anAmended Settlement Agreement (ASA). The ASA reflects an allowed return on equity (“ROE”) rate of 9.275% based on acommon equity ratio of approximately 51%. We are currently in year three of the multi-year rate plan (Rate Plan). On June30, 2021, the Division consented to an extension of the term of the Rate Plan such that the Company is not required to fileits next rate case so that new rates take effect no later than September 1, 2022. The ASA will remain in effect and theCompany will continue to operate under the current Rate Plan until a new Rate Plan is approved by the RIPUC. The Companyfiled a copy of the Division consent letter with the RIPUC on July 15, 2021. Base distribution rates will remain at the existingRate Year 3 levels until the next base rate case.

The ASA includes an Electric Transportation Initiative (the ET Initiative or Program) to facilitate the growth of Electric Vehicle(EV) adoption and scaling of the market for EV charging equipment to advance Rhode Island’s zero emission vehicles andgreenhouse gas emissions policy goals. The ET Initiative includes the following five components (i) Off-Peak Charging RebatePilot, (ii) Charging Station Demonstration Program, (iii) Discount Pilot for Direct Current Fast Charging (DCFC) StationAccounts, (iv) Fleet Advisory Services, and (v) Electric Transportation Initiative Evaluation. As of the end of Rate Year 2 TheCharging Station Demonstration Program achieved 72% of ET Initiative targets for Level 2 ports and 7% of the target for DCFCports. The ASA also includes two energy storage demonstration projects because storage is critical for achieving RhodeIsland’s clean energy future as it provides the ability to optimize system performance over time and allows intermittentrenewable resources to make a larger contribution to overall generation; both projects are on track for timely completion.

The ASA also introduces a new incentive-only performance incentive for System Efficiency: Annual Megawatt (“MW”)Capacity Savings, with maximum earnings ranging from approximately $0.4 million in 2019 to $0.9 million in 2021. In addition,the ASA identifies several additional metrics for tracking and reporting purposes only.

Recovery of Transmission Costs

The Company’s transmission facilities are operated in combination with the transmission facilities of its New Englandaffiliates, Massachusetts Electric Company (“MECO”) and NEP, as a single integrated system with NEP designated as thecombined operator. NEP collects the costs of the combined transmission asset pool including a return on those facilitiesunder NEP’s Tariff No. 1 from the ISO. The ISO allocates these costs among transmission customers in New England, inaccordance with the ISO Open Access Transmission Tariff (“ISO-NE OATT”).

According to the FERC order, the Company is compensated for its actual monthly transmission costs, with its authorizedmaximum ROE of 11.74% on its transmission assets. The amounts remitted by NEP to the Company for the years ended March31, 2021, 2020 and 2019 were $159.9 million, $141.8 million, and $144.8 million, respectively, which are eliminated asoperating revenues and operations and maintenance expenses within the accompanying statements of income.

On October 16, 2014, the FERC issued an order, Opinion No. 531-A, resetting the base ROE applicable to transmission assetsunder the ISO-NE OATT from 11.14% to 10.57% effective as of October 16, 2014 and establishing a maximum ROE of 11.74%.On March 3, 2015, the FERC issued an Order on Rehearing, Opinion No. 531-B, affirming the 10.57% base ROE and clarifyingthat the 11.74% maximum ROE applies to all individual transmission projects with ROE incentives previously granted by theFERC. On April 14, 2017, the U.S. Court of Appeals for the D.C. Circuit (Court of Appeals) vacated and remanded FERC's OpinionNo. 531 (and successor orders), through which the FERC had lowered the New England Transmission Owners (“NETO”) returnon equity from 11.14% to 10.57% and capped the total incentives at 11.74%.

On October 16, 2018, the FERC issued an order on all four complaints describing how it intends to address the issues thatwere remanded by the Court. The FERC proposed a new framework to determine whether an existing ROE is unjust andunreasonable and, if so, how to calculate a replacement ROE. The FERC stated that these calculations were merely preliminaryand asked the parties to the New England (“NE”) Complaint cases to brief FERC and check the numbers. National Grid alongwith other NETOs filed a brief supporting FERC’s new methodology and confirming the illustrative numbers that FERC arrived


at in the October 2018 order—a 10.41% base ROE. FERC has not issued a final order on our briefs and the base ROE in NEremains at a 10.57%. In November 2019, FERC issued an order in the Midcontinent Independent System Operator (“MISO”)ROE complaint dockets changing the way it arrives at a just and reasonable ROE. The effects of these changes result indrastically reduced base ROEs in the MISO region. In that MISO order, FERC made statements that it is setting new ROE policynationwide. In December 2019, the NETOs filed a supplemental brief in the NE ROE complaint dockets showing FERC thedetrimental effects on NE if the MISO order were applied to NE. In that brief, the NETOs ask FERC to reopen the record in NEso that we can submit more testimony. Other stakeholders had an opportunity to reply to our supplemental brief by January21st and did so, arguing that our request should be denied, and that the record in NE should not be reopened.

On January 21, 2020, the FERC issued an order granting rehearing for further consideration to give the FERC more time to acton the substantive issues of the MISO ROE proceedings. On May 21, 2020, FERC revised the methodology to determine MISOtransmission owner ROEs. FERC’s November order proposed to create “zones of reasonableness” based on averages of two(rather than four) models to judge whether ROEs are just and reasonable. ROEs were reduced from 10.32% to 9.88% whenFERC applied the revised methodology in two MISO ROE complaints. The May order relies on three models to estimate ROEs.The application of this new methodology increased ROEs in the MISO complaints from 9.88% to 10.02%. The Company doesnot believe the outcomes of these complaints will have a material impact on the Company’s financial condition, results ofoperations or cash flows.

Tax Act

On March 15, 2018, the FERC initiated multiple proceedings intended to adjust FERC-jurisdictional rates to reflect thecorporate tax changes as a result of the passage of the Tax Act. Of the proceedings initiated relevant to the Company is theNotice of Inquiry (“NOI”) seeking comments on the effects of the Tax Act on all FERC-jurisdiction rates and a Notice ofProposed Rulemaking (NOPR) issued as a result of the NOI. In response to the FERC NOI, the Company maderecommendations designed to mitigate the cash flow impacts of the expected refunds including providing flexibility regardingthe methods used to refund accumulated deferred income tax (“ADIT”) to customers and providing flexibility regarding thetime period of the flow back. In the NOPR, FERC proposed to give the flexibility the Company proposed.

On November 21, 2019, the FERC issued Order 864 to address ratemaking and regulatory reporting of excess or deficientADIT related to the Tax Act. The order applies to public utility transmission providers with formula rates and stated rates andprovides that public utilities with formula rates submit a compliance filing within 30 days of the effective date of the final ruleor in the public utilities next annual informational filing following the issuance of the final rule. The compliance filing mustdemonstrate how the public utilities formula rate adjusts rate base via a Rate Adjustment mechanism, returns or recoversexcess or deficient ADIT via an Income Tax Allowance Mechanism, and must include an ADIT worksheet to support the excessor deficient ADIT calculation and amortization. The ADIT worksheet must be populated and will be a new and permanentworksheet. The mechanisms and worksheet must remain applicable to any future changes to tax rates that give rise to excessor deficient ADIT, including changes to state and local tax rates. Excess or deficient ADIT associated with future tax ratechanges will automatically be included in a public utility’s formula rate without the need for a Section 205 filing. The orderdoes not prescribe a recovery/refund period for deficient/excess ADIT for unprotected excess/deficient ADIT that is notsubject to the normalization requirements. FERC will evaluate proposed amortization periods on a case by case basis. On April16, 2020, the FERC issued Order No. 864-A addressing requests for clarification, or in the alternative, rehearing, submitted inthe proceeding. FERC will evaluate proposed amortization periods on a case by case basis.

On June 29,2020, NEP, on behalf of NECO, submitted a compliance filing to address the application of Order 864 in NEP TariffNo. 1. The filing proposes changes to various revenue requirement calculations in the tariff for the inclusion of the RateAdjustment and Income Tax Allowance Mechanism. The filing also includes the populated permanent ADIT worksheet to beprovided with the issuance of final bills pursuant to the provisions of the tariff. NEP has proposed for NECO to amortizetransmission related protected property related excess or deficient ADIT associated with the 2017 Tax Act using the AverageRate Adjustment Mechanism (“ARAM”) and a 30-year amortization period on unprotected property related excess ordeficient balances. Other unprotected excess or deficient ADIT is proposed to be amortized over 10 years consistent withperiods approved in the RIPUC Docket addressing the Tax Act. NECO’s transmission related net excess ADIT balanceassociated with the Tax Act is $99.6 million.


The RIPUC opened a docket to address the change in the federal corporate income tax rate and other changes resulting fromthe Tax Act that was signed into law in December 2017. Specifically, the RIPUC requested the Company’s proposal for how itplanned to reduce rates associated with the income taxes recovered from customers on the equity component of the returnon investment included in revenue taxed at the new lower income tax rate of 21% effective January 1, 2018, and how itplanned to return to customers the reduction in its net deferred income tax liabilities resulting from the 14% decrease in thefederal income tax rate from 35%. Effective September 1, 2018, the Company reduced its revenue requirement for electricand gas distribution rates in effect for the impacts of the Tax Act as appropriate. On January 24, 2019, the Company filedwith the RIPUC a settlement agreement among the Company, the Division, the Office of Energy Resources, and the State ofRhode Island Office of the Lieutenant Governor, pursuant to which approximately $4.8 million and $3.1 million will beprovided to electric and gas customers, respectively, which reflect the benefits of the Company’s reduced federal corporateincome tax payment obligations for the period January 1, 2018 through August 31, 2018. The RIPUC approved the settlementagreement on May 17, 2019, as filed.

New England East-West Solution (“NEEWS”) Project

In September 2008, the Company, NEP, and Northeast Utilities jointly filed an application with the FERC to recover financialincentives for the NEEWS project, pursuant to the FERC’s Transmission Pricing Policy Order No. 679. NEEWS consists of aseries of inter-related transmission upgrades identified in the New England Regional System Plan and is being undertaken toaddress several reliability problems in Connecticut, Massachusetts, and Rhode Island. The Company’s share of the NEEWS-related transmission investment was approximately $560 million. The Company is fully reimbursed for its transmissionrevenue requirements on a monthly basis by NEP through NEP’s Tariff No. 1. Effective November 18, 2008, the FERC granted(1) an incentive ROE of 12.89% (125 basis points above the approved base ROE of 11.64%), (2) 100% construction work inprogress (“CWIP”) in rate base, and (3) recovery of plant abandoned for reasons beyond the companies’ control. As discussedin the preceding section, effective October 16, 2014, the FERC issued a series of orders establishing a maximum ROE of 11.74%that effectively caps the NEEWS incentive ROE at that level. The NEEWS upgrades were placed in service in December 2015.

Suspension of Service Terminations and Certain Collections Activities

At an open meeting on March 16, 2020, the RIPUC issued an order prohibiting all electric, natural gas, water, and sewerutilities from engaging in certain collections activities, including termination of residential and non-residential service fornonpayment (the “Order”). This moratorium expired on July 18, 2020 for commercial and industrial customers, onSeptember 30 for residential customers, and on November 1, 2020 for customers eligible for the low-income rate. On July25, 2021, the RIPUC’s extension of the moratorium on service disconnections for National Grid’s protected statuscustomers, including those on National Grid’s low-income rate, expired. Per the RIPUC’s June 25, 2021 order extending themoratorium to July 25, 2021, there will be no further extensions, unless there is substantial evidence of a major resurgenceof the COVID-19 Pandemic. To date, the RIPUC has not ordered any additional extensions of the moratorium so themoratorium is no longer in effect. The RIPUC’s order directing the Company to temporarily suspend late fees, interestcharges, credit card fees, debit card fees and ACH fees remains in effect, and the Company continues to track these costsfor later review by the RIPUC. The RIPUC will review these costs in the Company’s cost recovery filing in a separate docket(RIPUC Docket No. 5154). The Company continues to offer the 18-24-36-month payment plans per the RIPUC’s order.

On May 15, 2020, pursuant to the RIPUC’s directive, the Company filed a plan with the RIPUC and the Division that detailsthe Company’s plans for recommencing collection activities when the RIPUC lifts the moratorium on utility terminations (the“Plan”). The Plan consists of a four-phase approach, including initial efforts primarily focused on “bill health” messaging andassuring that customers are aware of the programs and services available to assist them with managing and paying their bills.The Company continues to progress through the phases of the Plan. The Company continues to submit arrearage data to theRIPUC and the Division on a weekly and monthly basis, respectively. On September 2, 2021, the Company filed its responsesto the RIPUC’s data requests regarding waived fees.

Advanced Metering Functionality and Grid Modernization

On January 21, 2021 the Company filed its Updated Advance Metering Functionality (“AMF”) Business Case and GridModernization Plan (“GMP”) with the RIPUC in accordance with the rate case settlement. The Updated AMF Business Case –


a foundational component of the GMP – seeks approval to deploy smart meters throughout the service territory. TheUpdated AMF Business Case includes approximately $224 million (20-year net present value)/$344 million (20-year nominal)of investment in smart meters and the associated communications infrastructure, as well as customer education andengagement based on a joint deployment scenario with New York. The GMP consists of a five-year implementation plan andten-year roadmap that serve as a guide for addressing anticipated distribution system needs. Although the Company is notseeking cost recovery for any specific GMP investment at this time, the Company is seeking approval of the GMP businesscase and benefit-cost analysis, which will provide regulatory clarity when seeking to implement such projects and pursue costrecovery as part of the Infrastructure, Safety and Reliability Plan or a future rate case. Pursuant to written order issued onJuly 14, 2021, the RIPUC stayed the AMF and GMP proceedings pending further consideration following the issuance of a finalOrder by the Division on the PPL Transaction. The RIPUC did not rule on whether or not to consolidate the matters.

COVID-19 Deferral Filing

On April 30, 2021, the Company filed a petition for approval to recognize regulatory assets related to COVID-19 Impacts(RIPUC Docket No. 5154). In its Petition, the Company seeks the PUC’s authorization to create regulatory assets andconsideration of future cost recovery for the following COVID-19 Costs: (1) the increased cost of customer accounts receivablethat the Company will be unable to collect as a result of the COVID-19 pandemic, and the executive orders and PUC ordersrestricting the Company’s collection activities as a result of the pandemic, which will result in increased net charge-offs; (2)lost revenue from unassessed late payment charges; and (3) charges to the Company for other fees that the Company haswaived pursuant to the RIPUC’s orders in R.I.P.U.C. Docket No. 5022. We will continue to monitor the proceeding, pendingany updates or new directive issued by the PUC.

Block Island Transmission System Surcharge Issues

The RIPUC has issued discovery to the Company regarding the Block Island Transmission System (“BITS”) surcharge calculationduring its 2021 Annual Retail Rates proceeding. During the Open Meeting in that docket, the Chairman questioned theCompany’s BITS arrangement. In addition, the Division has expressed ongoing concerns with the incremental costs associatedwith the reburial project related to the BITS cable and has retained FERC counsel. The Company is in discussions with theDivision on potential options regarding these matters; however, we cannot predict the outcome of these discussions.

PPL Transaction

Pursuant to a Share Purchase Agreement dated March 17, 2021, by and among PPL Energy Holdings, LLC, PPL Corporation(“PPL”), and National Grid USA (the “Transaction”), National Grid USA has agreed to sell 100 percent of the outstanding sharesof common stock in Narragansett to PPL Rhode Island Holdings, LLC (“PPL Rhode Island”), a wholly owned indirect subsidiaryof PPL. On May 4, 2021, PPL, PPL Rhode Island, National Grid USA, and Narragansett filed a joint petition with the Divisionseeking the Division’s consent and approval of the Transaction, which is currently pending in Docket No. D-21-09.

6. PROPERTY, PLANT AND EQUIPMENT

The following table summarizes property, plant and equipment, at cost and operating leases along with accumulated

depreciation and amortization:

March 31,

2021 2020

(in thousands of dollars)Plant and machinery $ 4,478,788 $ 4,133,095Land and buildings 135,500 129,368Assets in constructions 208,699 228,897Software and other intangibles 25,988 25,988Assets held for future use 15,028 15,028Operating leases 34,271 28,624


Total property, plant and equipment 4,898,274 4,561,000Accumulated depreciation and amortization (1,150,582) (1,083,552)Operating lease accumulated depreciation (13,401) (6,691)

Property, plant and equipment, net $ 3,734,291 $ 3,470,757

7. DERIVATIVE INSTRUMENTS

The Company utilizes derivative instruments to manage commodity price risk associated with its natural gas purchases. TheCompany’s commodity risk management strategy is to reduce fluctuations in firm gas sales prices to its customers.

The Company’s financial exposures are monitored and managed as an integral part of the Company’s overall financial riskmanagement policy. The Company engages in risk management activities only in commodities and financial markets whereit has an exposure, and only in terms and volumes consistent with its core business.

The volume of outstanding gas derivative instruments as of March 31, 2021 and March 31, 2020 was 38.5 million dekathermsand 40.6 million dekatherms, respectively.

Derivative Financial Instruments

The following tables reflect the gross and net amounts of the Company’s derivative assets and liabilities as of March 31,2021 and 2020:

March 31, 2021


Net amounts

Gross amounts Gross amounts of assets (liabilities) Gross amounts

of recognized offset in the presented in the not offset in the Net

assets (liabilities) Balance Sheets Balance Sheets Balance Sheets Amount

ASSETS: A B C=A+B D E=C-D

Other current assets

Gas contracts (rate recoverable) $ 4,953 $ - $ 4,953 $ 513 $4,440Gas contracts (not subject to raterecovery) 57 - 57 55 2

Other non-current assets

Gas contracts (rate recoverable) 630 - 630 124 506

Total $ 5,640 $ - $ 5,640 $ 692 $ 4,948

LIABILITIES:

Current liabilities

Gas contracts (rate recoverable) $ 5,982 $ - $ 5,982 $ 504 $ 5,478Gas contracts (not subject to raterecovery) 102 - 102 55 47

Other non-current liabilities

Gas contracts (rate recoverable) 5,823 - 5,823 124 5,699

Total 11,907 - 11,907 683 11,224

Net assets/(liabilities) $ (6,267) $ - $ (6,267) $ 9 $ (6,276)


March 31, 2020


Net amounts

Gross amounts Gross amounts of assets (liabilities) Gross amounts

of recognized offset in the presented in the not offset in the Net

assets (liabilities) Balance Sheets Balance Sheets Balance Sheets Amount

ASSETS: A B C=A+B D E=C-D

Other current assets

Gas contracts (rate recoverable) $ 90 $ - $ 90 $ 90 $ -Gas contracts (not subject to raterecovery) 64 - 64 54 10

Other non-current assets

Gas contracts (rate recoverable) 283 - 283 77 206

Total 437 - 437 221 216

LIABILITIES:

Current liabilities

Gas contracts (rate recoverable) 11,658 - 11,658 135 11,523Gas contracts (not subject to raterecovery) 110 - 110 54 56

Other non-current liabilities

Gas contracts (rate recoverable) 2,871 - 2,871 77 2,794

Total 14,639 - 14,639 266 14,373

Net liabilities $ (14,202) $ - $ (14,202) $ (45) $ (14,157)

The changes in fair value of the Company’s rate recoverable contracts are offset by changes in regulatory assets and liabilities.As a result, the changes in fair value of those contracts had no impact in the accompanying statements of income.

Credit and Collateral

The Company is exposed to credit risk related to transactions entered into for commodity price risk management. Credit riskrepresents the risk of loss due to counterparty non-performance. Credit risk is managed by assessing each counterparty’scredit profile and negotiating appropriate levels of collateral and credit support.

The Company enters into enabling agreements that allow for payment netting with its counterparties, which reduces itsexposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivablefrom the counterparty.

The credit policy for commodity transactions is managed and monitored by the Finance Committee to National Grid plc’sBoard of Directors (“Finance Committee”), which is responsible for approving risk management policies and objectives forrisk assessment, control and valuation, and the monitoring and reporting of risk exposures. NGUSA’s Energy ProcurementRisk Management Committee (“EPRMC”) is responsible for approving transaction strategies, annual supply plans, andcounterparty credit approval, as well as all valuation and control procedures. The EPRMC is chaired by the Vice President ofU.S. Treasury and reports to both the NGUSA Board of Directors and the Finance Committee.

The EPRMC monitors counterparty credit exposure and appropriate measures are taken to bring such exposures below thelimits, including, without limitation, netting agreements, and limitations on the type and tenor of trades. In instances wherea counterparty’s credit quality has declined, or credit exposure exceeds certain levels, the Company may limit its creditexposure by restricting new transactions with the counterparty, requiring additional collateral or credit support, andnegotiating the early termination of certain agreements. Similarly, the Company may be required to post collateral to itscounterparties.


The Company’s credit exposure for all commodity derivative instruments and applicable payables and receivables, net ofcollateral, and instruments that are subject to master netting agreements was a net liability of $6.3 million and $14.2 millionas of March 31, 2021 and March 31, 2020, respectively.

The aggregate fair value of the Company’s commodity derivative instruments with credit-risk-related contingent featuresthat were in a liability position as of March 31, 2021 and March 31, 2020 was $0.1 million and $6.6 million, respectively. TheCompany had no collateral posted for these instruments at March 31, 2020 and March 31, 2019. If the Company’s creditrating were to be downgraded by one or two levels, it would not be required to post any additional collateral. If theCompany’s credit rating were to be downgraded by three levels, it would have been required to post $0.2 million and $7.1million of additional collateral to its counterparties at March 31, 2021 and March 31, 2020, respectively.

8. FAIR VALUE MEASUREMENTS

The following tables present assets and liabilities measured and recorded at fair value on the balance sheet on a recurringbasis and their level within the fair value hierarchy as of March 31, 2021 and 2020:

March 31, 2021

Level 1 Level 2 Level 3 Total


Assets:

Derivative instruments

Gas contracts $ - $ 5,640 $ - $ 5,640

Securities 3,527 4,431 - 7,958

Total 3,527 10,071 - 13,598

Liabilities:


Gas contracts - 9,379 2,527 11,906

Total - 9,379 2,527 11,906

Net liabilities $ 3,527 $ 692 $ (2,527) $ 1,692

March 31, 2020

Level 1 Level 2 Level 3 Total


Assets:


Gas contracts $ - $ 437 $ - $ 437

Securities 2,674 3,729 - 6,403

Total 2,674 4,166 - 6,840

Liabilities:


Gas contracts - 9,097 5,542 14,639

Total - 9,097 5,542 14,639

Net assets (liabilities) $ 2,674 $ (4,931) $ (5,542) $ (7,799)

Derivative instruments: The Company’s Level 2 fair value derivative instruments consist of over-the-counter (“OTC”) gasswaps contracts with pricing inputs obtained from the New York Mercantile Exchange (“NYMEX”) and the Intercontinental


Exchange (“ICE”), except in cases where the ICE publishes seasonal averages or where there were no transactions within thelast seven days. The Company may utilize discounting based on quoted interest rate curves, including consideration of non-performance risk, and may include a liquidity reserve calculated based on bid/ask spread for the Company’s Level 2 derivativeinstruments. Substantially all of these price curves are observable in the marketplace throughout at least 95% of theremaining contractual quantity, or they could be constructed from market observable curves with correlation coefficients of95% or higher.

The Company’s Level 3 fair value derivative instruments consist of gas option and purchase and capacity transactions, whichare valued based on internally developed models. Industry-standard valuation techniques, such as the Black-Scholes pricingmodel, Monte Carlo simulation, and Financial Engineering Associates libraries are used for valuing such instruments. Forvaluations that include both observable and unobservable inputs, if the unobservable input is determined to be significant tothe overall inputs, the entire valuation is categorized in Level 3. This includes derivative instruments valued using indicativeprice quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable,consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includesassumptions about market risks such as liquidity, volatility, and contract duration. Such instruments are categorized in Level3 as the model inputs generally are not observable. The Company considers non-performance risk and liquidity risk in thevaluation of derivative instruments categorized in Level 2 and Level 3.

The significant unobservable inputs used in the fair value measurement of the Company’s gas derivative instruments areimplied volatility, gas forward curves. A relative change in commodity price at various locations underlying the open positionscan result in significantly different fair value estimates.

Securities: Securities are included in other non-current assets on the balance sheet and primarily include equity and debtinvestments based on quoted market prices (Level 1) and municipal and corporate bonds based on quoted prices of similartraded assets in open markets (Level 2).

9. EMPLOYEE BENEFITS

The Company participates with other NGUSA subsidiaries in qualified and non-qualified non-contributory defined benefitplans (the “Pension Plans”) and PBOP plans (together with the Pension Plan (the “Plans”), covering substantially allemployees.

Plan assets are maintained for all of NGUSA and its subsidiaries in commingled trusts. In respect of cost determination, planassets are allocated to the Company based on its proportionate share of the projected benefit obligations. The Plans’ costsare first directly charged to the Company based on the Company’s employees that participate in the Plans. Costs associatedwith affiliated service companies’ employees are then allocated as part of the labor burden for work performed on theCompany’s behalf. The Company applies deferral accounting for pension and PBOP expenses associated with its regulatedgas and electric operations. Any differences between actual costs and amounts used to establish rates are deferred andcollected from, or refunded to, customers in subsequent periods. Pension and PBOP service costs are included withinoperations and maintenance expense, and non-service costs are included within other income, net in the accompanyingstatements of income. Portions of the net periodic benefit costs disclosed below have been capitalized as a component ofproperty, plant, and equipment.

Pension Plans

The Qualified Pension Plans are defined benefit plans which provide most union employees, as well as non-union employeeshired before January 1, 2011, with a retirement benefit. Supplemental non-qualified, non-contributory executive retirementprograms provide additional defined pension benefits for certain executives. During the years ended March 31, 2021, 2020,and 2019, the Company made contributions of approximately $4.0 million, $4.3 million, and $12.0 million, respectively, tothe Qualified Pension Plans. The Company expects to contribute approximately $7.3 million to the Qualified Pension Plansduring the year ending March 31, 2022.Benefit payments to Pension Plan participants for the years ended March 31, 2021, 2020, and 2019 were approximately $28.7million, $28.4 million, and $27.6 million, respectively.


PBOP Plans

The PBOP Plans provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age andlength of service requirements and, in most cases, retirees must contribute to the cost of their coverage. For each of theyears ended March 31, 2021, 2020, and 2019, the Company made zero contributions to the PBOP Plans. The Company doesnot expect to contribute to the PBOP Plans during the year ending March 31, 2022.

Benefit payments to PBOP plan participants for the years ended March 31, 2021, 2020, and 2019 were approximately $11.2million, $9.1 million, and $9.8 million, respectively.

Net Periodic Benefit Costs

The Company’s total pension cost for the years ended March 31, 2021, 2020, and 2019 were $11.4 million, $7.0 million, and$9.8 million, respectively.

The Company’s total PBOP cost for the years ended March 31, 2021, 2020, and 2019 were $0.1 million, $1.0 million, and $2.8million, respectively.

Amounts Recognized in Regulatory Assets and Accumulated Other Comprehensive Income

The following tables summarize the Company’s changes in actuarial gains/losses and prior service costs recognized inregulatory assets and accumulated other comprehensive income (“AOCI”) as of March 31, 2021, 2020, and 2019:

Pension Plans


2021 2020 2019


Net actuarial (gain) loss $ (46,483) $ 48,706 $ 7,362

Amortization of net actuarial loss (11,892) (9,222) (9,659)

Amortization of prior service cost, net - (15) (20)

Total $ (58,375) $ 39,469 $ (2,317)

Included in regulatory assets $ (58,357) $ 39,309 $ (3,182)

Included in AOCI (18) 160 865

Total $ (58,375) $ 39,469 $ (2,317)


PBOP Plans


2021 2020 2019


Net actuarial (gain) loss $ (38,482) $ 6,752 $ (7,013)

Amortization of net actuarial loss (243) (442) (1,275)

Amortization of prior service benefit, net 20 20 20

Total $ (38,705) $ 6,330 $ (8,268)

Included in regulatory assets $ (38,705) $ 6,330 $ (8,268)

Total $ (38,705) $ 6,330 $ (8,268)

Amounts Recognized in AOCI and Regulatory Assets – not yet recognized as components of net actuarial loss

The following tables summarize the Company’s amounts in regulatory assets and accumulated other comprehensive incomeon the balance sheet that have not yet been recognized as components of net actuarial loss as of March 31, 2021, 2020, and2019

Pension Plans

March 31,

2021 2020 2019


Net actuarial loss $ 134,413 $ 192,788 $ 153,304

Prior service cost 2 2 17

Total $ 134,415 $ 192,790 $ 153,321

Included in regulatory assets $ 133,272 $ 191,629 $ 152,321

Included in AOCI 1,143 1,161 1,000

Total $ 134,415 $ 192,790 $ 153,321

PBOP Plans

March 31,

2021 2020 2019


Net actuarial (gain) loss $ (12,905) $ 25,820 $ 19,510

Prior service cost (benefit) 15 (5) (25)

Total $ (12,890) $ 25,815 $ 19,485

Included in regulatory assets $ (12,890) $ 25,815 $ 19,485

Total $ (12,890) $ 25,815 $ 19,485


Reconciliation of Funded Status to Amount Recognized

Pension Plans PBOP Plans

March 31, March 31,

2021 2020 2021 2020


Projected benefit obligation $ (636,782) $ (606,064) $ (205,963) $ (200,662)

Fair value of plan assets 625,259 543,434 184,778 140,828

Total $ (11,523) $ (62,630) $ (21,185) $ (59,834)

Current liabilities $ (195) $ (196) $ (93) $ (92)

Other non-current liabilities (11,328) (62,434) (21,092) (59,742)

Total $ (11,523) $ (62,630) $ (21,185) $ (59,834)

For the year end March 31, 2021, the net actuarial gains for pension and PBOP was largely the result of asset performanceand lower contract pricing negotiated on certain prescription benefit costs within the PBOP Plans, partially offset by lossesgenerated from the discount rate decrease. For the year end March 31, 2020, the net actuarial loss for pension and PBOPwas primarily driven by the discount rate decrease and asset performance below expectations. This loss was partially offsetby a gain related to a change in the mortality assumption and a PBOP assumption change for post-65 participation rates.For the year end March 31, 2019, the net actuarial loss for pension was primarily generated by the discount rate decrease.Whereas for the PBOP plans, the net gain was driven by assumptions changes related to pre-65 participation rates, offset bythe discount rate decrease.

Expected Benefit Payments

Based on current assumptions, the Company expects to make the following benefit payments subsequent to March 31, 2021:

(in thousands of dollars) Pension PBOPYears Ended March 31, Plans Plans

2022 $ 33,507 $ 9,3472023 34,762 9,5542024 36,126 9,6832025 37,458 10,0352026 38,834 10,3022027-2031 209,297 53,953

Total $ 389,984 $ 102,874


Assumptions Used for Employee Benefits Accounting

Pension Plans

As of and Years Ended March 31,

2021 2020 2019

Benefit Obligations:Discount rate 3.25% 3.65% 4.10%Rate of compensation increase (nonunion) 4.10% 3.50% 3.50%Rate of compensation increase (union) 4.05% 3.50% 3.50%Weighted average cash balance interest crediting rate 2.75% 2.75% 3.25%

Net Periodic Benefit Costs:Discount rate 3.65% 4.10% 4.10%Rate of compensation increase 3.50% 3.50% 3.50%Expected return on plan assets 6.00% 6.50% 6.25%Weighted average cash balance interest crediting rate 2.75% 3.25% 3.00%

PBOP Plans

As of and Years Ended March 31,

2021 2020 2019

Benefit Obligations:

Discount rate 3.25% 3.65% 4.10%

Net Periodic Benefit Costs:

Discount rate 3.65% 4.10% 4.10%

Expected return on plan assets 6.50%-7.00% 6.50%-7.25% 6.25%-6.75%

The Company selects its discount rate assumption based upon rates of return on highly rated corporate bond yields in themarketplace as of each measurement date. Specifically, the Company uses the Aon AA Only Bond Universe Curve along withthe expected future cash flows from the Company retirement plans to determine the weighted average discount rateassumption.

The expected rate of return for various passive asset classes is based both on analysis of historical rates of return and forwardlooking analysis of risk premiums and yields. Current market conditions, such as inflation and interest rates, are evaluated inconnection with the setting of the long-term assumptions. A small premium is added for active management of both equityand fixed income securities. The rates of return for each asset class are then weighted in accordance with the actual assetallocation, resulting in a long-term return on asset rate for each plan.


Assumed Health Cost Trend Rate

March 31,

2021 2020

Health care cost trend rate assumed for next year

Pre 65 6.80% 7.00%

Post 65 5.40% 5.50%

Prescription 7.70% 8.00%

Rate to which the cost trend is assumed to decline(ultimate) 4.50% 4.50%

Year that rate reaches ultimate trend

Pre 65 2031+ 2031+

Post 65 2031+ 2031+

Prescription 2031+ 2031+

Plan Assets

The Pension Plan is a trusted non-contributory defined benefit plan covering all eligible represented employees of theCompany and eligible non-represented employees of the participating National Grid companies. The PBOP Plans are both acontributory and non-contributory, trusteed, employee life insurance and medical benefit plan sponsored by the Company.Life insurance and medical benefits are provided for eligible retirees, dependents, and surviving spouses of the Company.

The Company manages the benefit plan investments for the exclusive purpose of providing retirement benefits to participantsand beneficiaries and paying plan expenses. The benefit plans’ named fiduciary is The Retirement Plans Committee (“RPC”).The RPC seeks to minimize the long-term cost of operating the Plans, with a reasonable level of risk. The investment objectivesof the plans are to maintain a level and form of assets adequate to meet benefit obligations to participants, to achieve theexpected long-term total return on the plans’ assets within a prudent level of risk and maintain a level of volatility that is notexpected to have a material impact on the Company’s expected contribution and expense or the Company’s ability to meetplan obligations.

The RPC has established and reviews at least annually the Investment Policy Statement (“IPS”) which sets forth the guidelinesfor how plan assets are to be invested. The IPS contains a strategic asset allocation for each plan which is intended to meetthe objectives of the plans by diversifying its funds across asset classes, investment styles and fund managers. Anasset/liability study typically is conducted periodically to determine whether the current strategic asset allocation continuesto represent the appropriate balance of expected risk and reward for the plan to meet expected liabilities. Each studyconsiders the investment risk of the asset allocation and determines the optimal mix of assets for the plan. The target assetallocation for 2021 reflects the results of such a pension study conducted in 2019. The Union PBOP Plan asset liability studywas conducted in 2021. As a result of that study the RPC approved changes to the Union PBOP asset allocation effective infiscal year 2022. The Non-Union PBOP Plan asset liability study is expected to be run within the next 12-18 months.

Individual fund managers operate under written guidelines provided by the RPC, which cover such areas as investmentobjectives, performance measurement, permissible investments, investment restrictions, trading and execution, andcommunication and reporting requirements. National Grid management in conjunction with a third party investment advisor,regularly monitors, and reviews asset class performance, total fund performance, and compliance with asset allocationguidelines. This information is reported to the RPC at quarterly meetings. The RPC changes fund managers and rebalancesthe portfolio as appropriate.


Equity investments are broadly diversified across U.S. and non-U.S. stocks, as well as across growth, value, and small andlarge capitalization stocks. Likewise, the fixed income portfolio is broadly diversified across market segments and is mainlyinvested in investment grade securities. Where investments are made in non-investment grade assets the higher volatility iscarefully judged and balanced against the expected higher returns. While the majority of plan assets are invested in equitiesand fixed income other asset classes are utilized to further diversify the investments. These asset classes include privateequity, real estate, and diversified alternatives. The objective of these other investments are enhancing long-term returnswhile improving portfolio diversification. For the PBOP Plans, since the earnings on a portion of the assets are taxable, thoseinvestments are managed to maximize after tax returns consistent with the broad asset class parameters established by theasset liability study. Investment risk and return are reviewed by the plan investment advisors, National Grid management andthe RPC on a regular basis. The assets of the plans have no significant concentration of risk in one country (other than theUnited States), industry or entity.

The target asset allocations for the benefit plans as of March 31, 2021 and 2020 are as follows:

Pension Plans Union PBOP Plans Non-Union PBOP Plans

March 31, March 31, March 31,

2021 2020 2021 2020 2021 2020

Equity 37% 37% 63% 63% 70% 70%

Diversified alternatives 10% 10% 17% 17% 0% 0%

Fixed income securities 40% 40% 20% 20% 30% 30%

Private equity 5% 5% 0% 0% 0% 0%

Real estate 5% 5% 0% 0% 0% 0%

Infrastructure 3% 3% 0% 0% 0% 0%

100% 100% 100% 100% 100% 100%


Fair Value Measurements

The following tables provide the fair value measurements amounts for the pension and PBOP assets at the Plan level:

March 31, 2021

Level 1 Level 2 Level 3 Not categorized Total


Pension Assets:

Investments

Equity $ 244,018 $ - $ - $ 891,362 $ 1,135,380

Diversified alternatives 70,409 - - 203,187 273,596

Corporate bonds - 514,588 - 168,106 682,694

Government securities 480 294,487 - 238,270 533,237

Private equity - - - 168,914 168,914

Real estate - - - 110,603 110,603

Infrastructure - - - 50,489 50,489

Total assets $ 314,907 $ 809,075 $ - $ 1,830,931 $ 2,954,913

Pending transactions (148,083)

Total net assets $ 2,806,830

PBOP Assets:

Investments

Equity $ 196,570 $ - $ - $ 335,943 $ 532,513

Diversified alternatives 45,255 - - 41,632 86,887

Corporate bonds - 3,792 - - 3,792

Government securities 14,864 157,025 - 1,032 172,921

Insurance contracts - - - 43,934 43,934

Total assets $ 256,689 $ 160,817 $ - $ 422,541 $ 840,047

Pending transactions 1,103

Total net assets $ 841,150


March 31, 2020

Level 1 Level 2 Level 3 Not categorized Total

(in thousands of dollars)Pension Assets:Investments

Equity $ 173,535 $ - $ - $ 630,567 $ 804,102Diversified alternatives 57,730 - - 173,255 230,985Corporate bonds - 412,698 - 142,101 554,799Government securities (4,072) 300,759 - 267,338 564,025Private equity - - - 131,200 131,200Real estate - - - 115,522 115,522Infrastructure - - - 48,687 48,687Insurance contracts - - - 3,507 3,507

Total assets $ 227,193 $ 713,457 $ - $ 1,512,177 $ 2,452,827

Pending transactions (111,173)

Total net assets $ 2,341,654

PBOP Assets:Investments

Equity $ 140,528 $ - $ - $ 224,383 $ 364,911Diversified alternatives 33,367 - - 32,954 66,321Corporate bonds - 2,895 - - 2,895Government securities 13,584 147,495 - 1,034 162,113Insurance contracts - - - 31,473 31,473

Total assets $ 187,479 $ 150,390 $ - $ 289,844 $ 627,713

Pending transactions 1,362

Total net assets $ 629,075

The methods used to fair value pension and PBOP assets are described below:

Equity: Equity includes both actively- and passively-managed assets with investments in domestic equity index funds as wellas international equities.

Diversified alternatives: Diversified Alternatives consist of holdings of global tactical assets allocation funds that seek toinvest opportunistically in a range of asset classes and sectors globally.

Corporate bonds: Corporate Bonds consist of debt issued by various corporations and corporate money market funds.Corporate Bonds also includes small investments in preferred securities as these are used in the fixed income portfolios asyield producing investments. In addition, certain fixed income derivatives are included in this category such as credit defaultswaps to assist in managing credit risk.

Government securities: Government Securities includes US agency and treasury securities, as well as state and localmunicipal bonds. The plans also include a small amount of Non-US government debt which is also captured here. USGovernment money market funds are also included. In addition, interest rate futures and swaps are held as a tool to manageinterest rate risk.

Private equity: Private equity consists of limited partnerships investments where all the underlying investments are privatelyheld. This consists of primarily buy-out investments with smaller allocations to venture capital.

Real estate: Real estate consists of limited partnership investments primarily in US core open end real estate funds as well assome core plus closed end real estate funds.


Infrastructure: Infrastructure consists of limited partnerships investments that seek to invest in physical assets that areconsidered essential for a society to facilitate the orderly operation of its economy. Investments in infrastructure typicallyinclude transportation assets (such as airports and toll roads) and utility type assets. Investments in infrastructure funds areutilized as a diversifier to other asset classes within the pension portfolio. Infrastructure investments are also typically incomeproducing assets.

Insurance contracts: Insurance contracts consists of Trust Owned Life Insurance.

Pending transactions: These are short term cash transactions that are expected to settle within a few days of themeasurement date.

Defined Contribution Plan

NGUSA has defined contribution retirement plans that cover substantially all employees. For each of the years ended March31, 2021, 2020, and 2019, the Company recognized an expense in the accompanying statement of income of $3.1 million formatching contributions.

10. CAPITALIZATION

The aggregate maturities of long-term debt for the years subsequent to March 31, 2021 are as follows:

(in thousands of dollars) Maturities of

March 31, Long-Term Debt

2022 $ 1,375

2023 13,875

2024 750

2025 750

2026 750

Thereafter 1,500,000

Total $ 1,517,500

The Company’s debt agreements and banking facilities contain covenants, including those relating to the periodic and timelyprovision of financial information by the issuing entity and financial covenants such as restrictions on the level ofindebtedness. Failure to comply with these covenants, or to obtain waivers of those requirements, could in some cases triggera right, at the lender’s discretion, to require repayment of some of the Company’s debt and may restrict the Company’s abilityto draw upon its facilities or access the capital markets. As of March 31, 2021 and 2020, the Company was in compliance withall such covenants.

Debt Authorizations

The Company had regulatory approval from the FERC to issue up to $400 million of short-term debt. The authorization wasrenewed with an effective date of January 11, 2021 and expires on October 14, 2022. The Company had no external short-term debt as of March 31, 2021 and 2020. Refer to Note 15, “Related Party Transactions” under “Intercompany Money Pool”for short-term debt outstanding with associated companies.

A new financing petition was filed with the RIPUC and approved on January 19, 2020 authorizing the issuance of up to $900million of new long term debt through March 31, 2023. In April 2020, the Company issued $600 million of unsecured long-term debt at 3.395% with a maturity date of April 9, 2030, resulting in $300 million of remaining authorization.


First Mortgage Bonds

As of March 31, 2021, the Company had $17.5 million of FMB outstanding. Substantially all of the assets used in the gasbusiness of the Company are subject to the lien of the mortgage indentures under which these FMB have been issued. TheFMB have annual sinking fund requirements totaling approximately $1.4 million.

The Company has a maximum 70% of debt-to-capitalization covenant. Furthermore, if at any time the Company’s debtexceeds 60% of the total capitalization, each holder of bonds then outstanding, shall receive effective as of the first date ofsuch occurrence, a one time, and permanent, 0.20% increase in the interest rate paid by the Company on its bonds. As ofMarch 31, 2021, and 2020, the Company was in compliance with this covenant.

Dividend Restrictions

Pursuant to the preferred stock arrangement, as long as any preferred stock is outstanding, certain restrictions on paymentof common stock dividends would come into effect if the common stock equity was, or by reason of payment of suchdividends became, less than 25% of total capitalization. The Company was in compliance with this covenant and accordingly,the Company was not restricted as to the payment of common stock dividends under the foregoing provisions as of March31, 2021 or 2020.

Cumulative Preferred Stock

The Company has certain issues of non-participating cumulative preferred stock outstanding where it can be redeemed atthe option of the Company. There are no mandatory redemption provisions on the Company’s cumulative preferred stock. Asummary of cumulative preferred stock is as follows:

Shares Outstanding Amount

March 31, March 31, Call

Series 2021 2020 2021 2020 Price

(in thousands of dollars, except per share and number of shares data)

$50 par value -

4.50% Series 49,089 49,089 $ 2,454 $ 2,454 $ 55.000

The Company did not redeem any preferred stock during the years ended March 31, 2021, 2020, or 2019. The annual dividendrequirement for cumulative preferred stock was $0.1 million for the years ended March 31, 2021, 2020 and 2019.

11. INCOME TAXES

Components of Income Tax Expense


2021 2020 2019


Current federal income tax expense (benefit) $ 19,169 $ 23,920 $ (12,398)

Deferred federal tax expense 10,657 2,976 36,415

Amortized investment tax credits (1) - (1) (16)

Total deferred tax expense 10,657 2,975 36,399

Total income tax expense $ 29,826 $ 26,895 $ 24,001

(1) Investment tax credits (“ITC”) are accounted for using the deferral and gross up method of accounting and amortized over the depreciable life of the

property giving rise to the credits.


Statutory Rate Reconciliation

The Company's effective tax rates for the years ended March 31, 2021, 2020 and 2019 are 18.1%, 18.0% and 17.9%,respectively. The following table presents a reconciliation of income tax expense (benefit) at the federal statutory tax rate of21% to the actual tax expense:


2021 2020 2019


Computed tax $ 34,608 $ 31,353 $ 28,231

Change in computed taxes resulting from:

Temporary differences flowed through (4,687) (4,655) (4,293)

Other items, net (95) 197 63

Total (4,782) (4,458) (4,230)

Total income tax expense $ 29,826 $ 26,895 $ 24,001

The Company is included in the NGNA and subsidiaries consolidated federal income tax return. The Company has joint andseveral liability for any potential assessments against the consolidated group.

Deferred Tax Components

March 31,

2021 2020


Deferred tax assets:

Allowance for doubtful accounts $ 13,312 $ 9,091

Postretirement benefits and other employee benefits 10,821 29,126



Net operating losses 48,321 56,451

Other items – net 17,557 17,206

Total deferred tax assets 204,747 226,186

Deferred tax liabilities:

Property related differences 438,025 420,471

Regulatory assets 110,015 128,530

Amortization of intangibles 47,872 44,119

Other items 1,057 384

Total deferred tax liabilities 596,969 593,504

Deferred income tax liabilities, net $ 392,222 $ 367,318


Net Operating Losses

The amounts and expiration dates of the Company's net operating losses carryforwards as of March 31, 2021 are as follows:

Expiration of Net Operating Losses Gross Carryforward Amount Expiration Period


Federal $ 365,964 2033 – 2038

As a result of the accounting for uncertain tax positions, the amount of deferred tax assets reflected in the financialstatements is less than the amount of the tax effect of the federal and state net operating losses carryforward reflected onthe income tax returns.

Federal Income Tax Audit

During the year ended March 31, 2021, the Company reached a settlement with the IRS for the tax years ended March 31,2013, March 31, 2014 and March 31, 2015. As a result of the settlement, the Company received a refund for tax and interestof $4.7 million.

During the year ended March 31, 2021, the IRS informed the Company that it does not intend to audit the Company’s incometax returns for the periods ended March 31, 2016 and 2017 and commenced its examination of the next audit cycle whichincludes periods ended March 31, 2018 and 2019. While the income tax returns for fiscal years 2016 and 2017 are notcurrently being audited by the IRS, the statute of limitations for these tax periods does not expire until December 31,2021. Therefore, the income tax returns for the years ended March 31, 2016 through March 31, 2021 remain subject toexamination by the IRS.

The following table indicates the earliest tax year subject to examination for each major jurisdiction:

Jurisdiction Tax Year

Federal March 31, 2016

The Company is not subject to state income tax due to the State of Rhode Island's exclusion of public utilities from incometax.

Uncertain Tax Positions

The Company recognizes interest related to unrecognized tax benefits in other interest, including affiliate interest and relatedpenalties, if applicable, in other income, net, in the accompanying statements of income. As of both March 31, 2021 and2020, the Company has accrued for interest related to unrecognized tax benefits of $0.3 million. During the years endedMarch 31, 2021, 2020 and 2019, the Company recorded interest expense of zero, zero, and $0.3 million, respectively. No taxpenalties were recognized during the years ended March 31, 2021, 2020 or 2019.

It is reasonably possible that other events will occur during the next twelve months that would cause the total amount ofunrecognized tax benefits to increase or decrease. However, the Company does not believe any such increases or decreaseswould be material to its results of operations, financial position, or cash flows.

12. ENVIRONMENTAL MATTERS

The normal ongoing operations and historic activities of the Company are subject to various federal, state, and localenvironmental laws and regulations. Under federal and state Superfund laws, potential liability for the historic contaminationof property may be imposed on responsible parties jointly and severally, without regard to fault, even if the activities werelawful when they occurred.


The United States Environmental Protection Agency (“EPA”), the Massachusetts Department of Environmental Protection(“DEP”), and the Rhode Island Department of Environmental Management (“DEM”) have alleged that the Company is apotentially responsible party under state or federal law for the remediation of a number of sites at which hazardous waste isalleged to have been disposed. The Company’s most significant liabilities relate to former Manufactured Gas Plant (“MGP”)facilities formerly owned by the Blackstone Valley Gas and Electric Company and the Rhode Island gas distribution assets ofNew England Gas. The Company is currently investigating and remediating, as necessary, those MGP sites and certain otherproperties under agreements with the EPA, DEM and DEP. Expenditures incurred for the years ended March 31, 2021, 2020,and 2019 were $7.3 million, $1.9 million, and $1.8 million, respectively.

The Company estimated the remaining costs of environmental remediation activities were $111.8 million and $119.8 millionas of March 31, 2021 and 2020, respectively. These costs are expected to be incurred over approximately 37 years, and theseundiscounted amounts have been recorded as estimated liabilities on the balance sheet. However, remediation costs foreach site may be materially higher than estimated, depending on changing technologies and regulatory standards, selectedend use for each site, and actual environmental conditions encountered. The Company has recovered amounts from certaininsurers and potentially responsible parties, and, where appropriate, the Company may seek additional recovery from otherinsurers and from other potentially responsible parties, but it is uncertain whether, and to what extent, such efforts will besuccessful.

The RIPUC has approved a settlement agreement that provides for rate recovery of remediation costs of former MGP sitesand certain other hazardous waste sites located in Rhode Island. Under that agreement, qualified costs related to these sitesare paid out of a special fund established as a regulatory liability on the balance sheet. Rate-recoverable contributions ofapproximately $3.1 million are added annually to the fund, along with interest and any recoveries from insurance carriersand other third-parties. Accordingly, as of March 31, 2021 and 2020, the Company has recorded environmental regulatoryassets of $110.0 million and $119.0 million, respectively, and environmental regulatory liabilities of $16.2 million and $18.8million, respectively (See Note 4, “Regulatory Assets and Liabilities” for additional details).

The Company believes that its ongoing operations, and its approach to addressing conditions at historic sites, are insubstantial compliance with all applicable environmental laws. Where the Company has regulatory recovery, it believes thatthe obligations imposed on it because of the environmental laws will not have a material impact on its results of operationsor financial position.

13. COMMITMENTS AND CONTINGENCIES

Purchase Commitments

The Company has several long-term contracts for the purchase of electric power. Substantially all of these contracts requirepower to be delivered before the Company is obligated to make payment. Additionally, the Company has entered into variouscontracts for gas delivery, storage, and supply services. Certain of these contracts require payment of annual demand charges,which are recoverable from customers. The Company is liable for these payments regardless of the level of service requiredfrom third-parties.


The Company’s commitments under these long-term contracts for the years subsequent to March 31, 2021 are summarizedin the table below:

(in thousands of dollars) EnergyMarch 31, Purchases

2022 $ 266,4932023 104,6932024 50,5832025 47,5982026 39,870Thereafter 349,765

Total $ 859,002

Long-term Contracts for Renewable Energy

Deepwater Agreement

The 2009 Rhode Island law required the Company to solicit proposals for a small scale renewable energy generation projectof up to eight wind turbines with an aggregate nameplate capacity of up to 30 MW to benefit the Town of New Shoreham.The renewable energy generation project also included a transmission cable to be constructed between Block Island and themainland of Rhode Island. On June 30, 2010, the Company entered into a 20-year Amended Power Purchase Agreement(“PPA”) with Deepwater Wind Block Island LLC (“Deepwater”), which was approved by the RIPUC in August 2010. The windturbines reached commercial operation on December 12, 2016 and the PPA is being accounted for as a capital lease. TheCompany also negotiated a Transmission Facilities Purchase Agreement (“Facilities Purchase Agreement,” or “FPA”) withDeepwater to purchase the permits, engineering, real estate, and other site development work for construction of theundersea transmission cable (collectively, the “Transmission Facilities”). On April 2, 2014, the Division issued its ConsentDecision for the Company to execute the FPA with Deepwater. In July 2014, four agreements were filed with the FERC, inpart, for approval to recover the costs associated with the transmission cable and related facilities (the “Project”) that will beallocated to the Company and Block Island Power Company through transmission rates. On September 2, 2014, the FERCaccepted all four agreements thus approving cost recovery for the Project, with no conditions, that will apply to theCompany’s costs, as well as those of NEP. The agreements went into effect on September 30, 2014. On January 30, 2015, theCompany closed on its purchase of the Transmission Facilities from Deepwater. The Company placed the TransmissionFacilities into service on October 31, 2016.

Three-State Procurement

On April 9, 2018, the RIPUC approved eight long-term (20-year) contracts for the purchase of the electricity and renewableenergy credits from eight separate generating facilities pursuant to the Rhode Island Long-Term Contracting Standard. TheCompany will purchase the actual output generated by the individual facilities, which in aggregate represents approximately39 MWs of nameplate capacity. Because the contracts were approved pursuant to the Rhode Island Long-Term ContractingStandard, the Company may collect 2.75% remuneration on the annual payments made under the contracts. The contractsresulted from a three-state solicitation for renewable energy generation proposals.

Offshore Wind Energy Procurement

On December 6, 2018, the Narragansett Electric Company entered into a 20-year PPA with DWW Rev I, LLC (“RevolutionWind”), for the purchase of the electricity and renewable energy credits generated by the offshore windfarm proposed byRevolution Wind, that will have a capacity of up to 408 MW. The anticipated commercial operations date for the windfarm isin January 2024. On May 28, 2019, at an open meeting, the RIPUC approved the contract without remuneration. The writtenorder approving the agreement and that Company will be able to recover the cost incurred under the agreement was issuedby the RIPUC on June 7, 2019.


Annual Solicitations

The 2009 Rhode Island law (Long Term Contracting Standard (“LTCS”)) also requires that, beginning on July 1, 2010, theCompany conduct four annual solicitations for proposals from renewable energy developers and, provided commerciallyreasonable proposals have been received, enter into long-term contracts for the purchase of capacity, energy, and attributesfrom newly developed renewable energy resources. The Company’s four solicitations have resulted in four PPAs that havebeen approved by the RIPUC:

- First Solicitation: On July 28, 2011, the RIPUC approved a 15-year PPA with Orbit Energy Rhode Island, LLC for a 3.2MW anaerobic digester biogas project located in Johnston, Rhode Island. The facility reached commercial operationon August 24, 2017.

- Second Solicitation: On May 11, 2012, the RIPUC approved a 15-year PPA with Black Bear Development Holdings,LLC for a 3.9 MW run-of-river hydroelectric plant located in Orono, Maine. The facility reached commercial operationon November 22, 2013.

- Third Solicitation: On October 25, 2013, the RIPUC approved a 15-year PPA with Champlain Wind, LLC for a 48 MWland-based wind project located in Carroll Plantation and Kossuth Township, Maine. The PPA was terminated onJanuary 23, 2017 because one of the required permits for the project was rejected. The impact of this terminationis that the Company then needed to backfill the MW capacity from that project to meet the 90 MW minimum long-term capacity requirements under the state statute, that it fulfilled in the fifth solicitation.

- Fourth Solicitation: On October 29, 2015, the RIPUC approved a 15-year PPA with Copenhagen Wind Farm, LLC foran 80 MW land-based wind project located in Denmark, New York. The facility reached commercial operation onDecember 27, 2018.

In 2014 the LTCS was amended to allow for additional solicitations until the 90 MW contracting capacity requirement wasmet.

- Fifth Solicitation: On May 11, 2020, the RIPUC approved a 20 year PPA with Gravel Pit Solar II, LLC for a 49.5 MWland based bifacial solar project located in East Windsor, CT. The anticipated commercial operation date is March31, 2023.

As approved by the RIPUC, the Company is allowed to pass through commodity-related / purchased power costs to customersand collect remuneration equal to 2.75%.

Aquidneck Island

On January 21, 2019, we suffered a significant loss of gas supply to the distribution system that serves our customers onAquidneck Island in Rhode Island. As a result, we made the decision to interrupt the gas service to the Aquidneck Islandsystem to protect the safety of our customers and the public. Overall, approximately 7,500 customers lost their gas service.On October 30, 2019, the RI Division issued their Summary Investigation Report regarding the gas service interruption. In thereport, the Division identified the causes of the outages, which included multiple factors, some of which were outside thecontrol of the Company. The Division’s Report also recommended several gas system improvements, many of which we haveaddressed already. On December 13, 2019, we filed our response to the Division’s Report and continue to meet with theDivision on a quarterly basis regarding winter reliability issues for Aquidneck Island and Rhode Island. On September 23,2020, we published a long-term capacity study for energy solutions for Aquidneck Island for stakeholder feedback. We aregathering stakeholder feedback on a hybrid model approach that will offset gas demand growth with advanced non-infrastructure solutions while addressing existing gas capacity and vulnerability challenges with an alternate LNG solution.On May 18, 2021, we attended an informational session at the Rhode Island Public Utilities Commission to update theCommission on the Company’s long-term capacity solutions for Aquidneck Island.

In November 2019, the Company was first served with an amended class action complaint on behalf of business owners onAquidneck and a separate class action on behalf of individuals in the affected areas. Further amendments to the complaintshave subsequently been filed. The Company is actively defending against these class action complaints. Additionally, sixsubrogation actions allegedly related to event have been filed against the Company to date.


Legal Matters

The Company is subject to various legal proceedings arising out of the ordinary course of its business. The Company does notconsider any of such proceedings to be material, individually or in the aggregate, to its business or likely to result in a materialadverse effect on its results of operations, financial position, or cash flows.

New York Public Service Commission Investigation

On June 17, 2021, five former NGUSA employees in the downstate New York facilities department were arrested on federalcharges alleging fraud and bribery. It is NGUSA’s understanding that the investigation by the US Attorney’s Office and FBIremains ongoing; NGUSA is a victim of the alleged crimes and will continue to comply with the government’sinvestigation. The New York Public Service Commission, the Massachusetts Department of Public Utilities, and the RhodeIsland Public Utilities Commission have each issued requests for information related to the alleged criminal conduct. At thistime, it is not possible to predict the outcome of the regulatory review or determine the amount, if any, of any potentialliabilities that may be incurred by the Company related to this matter. However, the Company does not expect this matterwill have a material adverse effect on its results of operations, financial position or cash flows.

Energy Efficiency Programs Investigation

NGUSA is performing an internal investigation regarding conduct associated with the Company’s energy efficiencyprograms. At this time, it is not possible to predict the outcome of the investigation or determine the amount, if any, of anyliabilities that may be incurred in connection with it by the Company. However, the Company does not expect this matterwill have a material adverse effect on its results of operations, financial position or cash flows.

14. LEASES

The Company has no finance leases as of March 31, 2021 or 2020. The Company has various operating leases, primarilyrelated to a transmission line, buildings, land, and fleet vehicles used to support the electric and gas operations, with leaseterms ranging between 4 and 50 years. The expense related to operating leases was $8.0 million and $7.9 million for theyears ended March 31, 2021 and 2020, respectively.

Certain building leases provide the Company with an option to extend the lease term. The Company has included the periodscovered by the extension options in its determination of the lease term when management believes it is reasonably certainthe Company will exercise its option.

In measuring lease liabilities, the Company excludes variable lease payments, other than those that depend on an index or arate, or are in substance fixed payments, and includes lease payments made at or before the commencement date. Thevariable lease payments were not material for the year ended March 31, 2021.

Lease liabilities are recognized based on the present value of the lease payments over the lease term at the commencementdate. For any leases that do not provide an implicit rate, the Company uses an estimate of its collateralized incrementalborrowing rate based on the information available at the commencement date to determine the present value of futurepayments. Operating lease ROU assets are included in property, plant and equipment, net, and operating lease liabilities areincluded in other current liabilities and other noncurrent liabilities on the balance sheet.

As of March 31, 2021, the Company does not have material rights or obligations under operating leases that have not yetcommenced.


The following table presents the components of cash flows arising from lease transactions and other operating lease-relatedinformation:

Year ended March 31,

2021 2020


Cash paid for amounts included in lease liabilities

Operating cash flows from operating leases $ 8,006 $ 7,889

ROU assets obtained in exchange for new operating lease liabilities $ 6,108 $ 2,644

Weighted-average remaining lease term – operating leases 5 4

Weighted-average discount rate – operating leases 2.53% 2.65%

The following contains the Company’s maturity analysis of its operating lease liabilities as of March 31, 2021, showing theundiscounted cash flows on an annual basis reconciled to the undiscounted cash flows of the operating lease liabilitiesrecognized in the comparative balance sheet:

Operating Leases

Year Ending March 31, (in thousands of dollars)

2022 $ 6,662

2023 5,436

2024 3,945

2025 2,127

2026 1,446

Thereafter 2,457

Total future minimum lease payments $ 22,073

Less: imputed interest (1,203)

Total $ 20,870

Reported as of March 31, 2021:

Current lease liability $ 6,210

Non-current lease liability 14,660

Total $ 20,870

There are certain leases in which the Company is the lessor. Revenue under such leases was immaterial for the years endedMarch 31, 2021 and 2020.

15. RELATED PARTY TRANSACTIONS

Accounts Receivable from and Accounts Payable to Affiliates

NGUSA and its affiliates provide various services to the Company, including executive and administrative, customer services,financial (including accounting, auditing, risk management, tax, and treasury/finance), human resources, informationtechnology, legal, and strategic planning, that are charged between the companies and charged to each company.


The Company records short-term receivables from, and payables to, certain of its affiliates in the ordinary course of business.The amounts receivable from, and payable to, its affiliates do not bear interest and are settled through the intercompanymoney pool. A summary of outstanding accounts receivable from affiliates and accounts payable to affiliates is as follows:

Accounts Receivable Accounts Payable

from Affiliates to Affiliates

March 31, March 31,

2021 2020 2021 2020


New England Power Company $ 13,803 $ 12,872 $ 27,764 $ 25,937

NGUSA Service Company 3,498 4,571 29,423 24,754

Other 85 2,231 3,200 3,740

Total $ 17,386 $ 19,674 $ 60,387 $ 54,431

As discussed in Note 5 “Rate Matters,” NEP operates the pooled transmission facilities of MECO, the Company, and NEP as asingle integrated system (“NEPOOL”) under NEP’s Tariff No. 1. These transmission services are regulated by both ISO-NE andby the FERC. NEP charges ISO-NE for these transmission services. As NEP is the sole operator of NEPOOL assets, ISO-NErevenues are remitted from NEP to the Company representing the substantial portion of the affiliated accounts receivabledue from NEP.

In turn, ISO-NE charges the Company for regional network services (“RNS”) with some of those charges being associated withthe Company-owned transmission assets in the NEPOOL. As of March 31, 2021 and March 31, 2020, $18.6 million and $17.2million of the unpaid charges from ISO-NE to the Company have been presented as an affiliated payable to NEP related tothese Company-owned transmission assets, respectively. Additionally, NEP also charges the Company local network service(“LNS”) rates. Amounts paid to NEP for LNS for the years ended March 31, 2021, 2020 and 2019 were $52.7 million, $57.4million, and $46.5 million, respectively. These amounts are presented within operations and maintenance expense within theaccompanying statements of income.

Advances from Affiliates

Since December 2008, the Company had FERC and board authorization to borrow up to $250 million as deemed necessaryfor working capital needs. The advance is non-interest bearing. As of March 31, 2021 and 2020, the Company had nooutstanding advances from affiliates.

Intercompany Money Pool

The settlement of the Company’s various transactions with NGUSA and certain affiliates generally occurs via theintercompany money pool in which it participates. The Company is a participant in the Regulated Money Pool and can bothborrow and invest funds. Borrowings from the Regulated Money Pool bear interest in accordance with the terms of theRegulated Money Pool Agreement. As the Company fully participates in the Regulated Money Pool rather than settlingintercompany charges with cash, all changes in the intercompany money pool balance are reflected as investing or financingactivities in the accompanying statements of cash flows. For the purpose of presentation in the statements of cash flows, itis assumed all amounts settled through the intercompany money pool are constructive cash receipts and payments, andtherefore are presented as such.

The Regulated Money Pool is funded by operating funds from participants. NGUSA has the ability to borrow up to $3.0 billionfrom National Grid plc for working capital needs including funding of the Regulated Money Pool, if necessary. The Companyhad short-term intercompany money pool investments of $158.6 million and borrowings of $351.4 million as of March 31,2021 and 2020, respectively. The average interest rates for the intercompany money pool were 0.7%, 2.4%, and 2.4% for theyears ended March 31, 2021, 2020, and 2019, respectively.


Service Company Charges

The affiliated service companies of NGUSA provide certain services to the Company at cost without a markup. The servicecompany costs are generally allocated to associated companies through a tiered approach. First and foremost, costs aredirectly charged to the benefited company whenever practicable. Secondly, in cases where direct charging cannot be readilydetermined, costs are allocated using cost/causation principles linked to the relationship of that type of service, such asnumber of employees, number of customers/meters, capital expenditures, value of property owned, and total transmissionand distribution expenditures. Lastly, all other costs are allocated based on a general allocator determined using a 3-pointformula based on net margin, net property, plant and equipment, and operations and maintenance expense.

Charges from the service companies of NGUSA to the Company are mostly related to traditional administrative supportfunctions, of which for the years ended March 31, 2021, 2020, and 2019 were $270.6 million, $250.8 million, and $229.7million, respectively.

Documents

The Narragansett Electric Company